The Energy Regulation and Markets Review - Stikeman Elliott

The Energy
Regulation
and Markets
Review
Editor
David L Schwartz
Law Business Research

The Energy Regulation
and Markets Review

The Energy
Regulation
and Markets
Review
Editor
David L Schwartz
Law Business Research Ltd

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acknowledgements
Afridi & Angell
Anderson Mōri & Tomotsune
Banwo & Ighodalo
D’Empaire Reyna Abogados
Djingov, Gouginski, Kyutchukov & Velichkov,
attorneys and counsellors at law
Goltsblat BLP
Gómez-Pinzón Zuleta
GonzÁlez Calvillo, SC
Hengeler Mueller
Hogan Lovells
Kvale Advokatfirma DA
L O Baptista Schmidt Valois Miranda Ferreira Agel
LALIVE
Latham & Watkins AARPI
Latham & Watkins LLP
Makarim & Taira S
Mannheimer Swartling
i

Acknowledgements
Minter Ellison
Paksoy Attorneys at Law
PotamitisVekris Law Partnership
Schoenherr Attorneys at Law
Stek
Stikeman Elliott LLP
Trilegal
White & Case LLP (South Africa)
Zul Rafique & Partners
ii

contents
Editor’s Preface
...................................................................................................ix
David L Schwartz
Chapter 1 Australia .............................................................................. 1
Mitzi Gilligan, Eliza Bartlett, Carolyn Vigar, Darshini
Nanthakumar, Rudi Kruse, Genevieve Watt and Nicholas Liau
Chapter 2 Austria ................................................................................ 23
Bernd Rajal and Guenther Grassl
Chapter 3 brazil ................................................................................... 34
Guilherme Guerra D’Arriaga Schmidt
Chapter 4 Bulgaria ............................................................................. 45
Yassen Spassov
Chapter 5 Canada ................................................................................ 62
Patrick Duffy, Brad Grant, Erik Richer La Flèche
and Glenn Zacher
Chapter 6 Colombia............................................................................ 76
Patricia Arrázola-Bustillo and Fabio Ardila
Chapter 7 France ................................................................................. 86
Fabrice Fages and Myria Saarinen
Chapter 8 Germany ............................................................................. 97
Dirk Uwer
Chapter 9 Greece ............................................................................... 108
Euripides Ioannou and Dimitra Rachouti
Chapter 10 India ................................................................................... 120
Akshay Jaitly, Sitesh Mukherjee, Neeraj Menon
and Vibhu Sharma
v

Contents
Chapter 11 Indonesia ......................................................................... 132
Pudji W Purbo
Chapter 12 Italy .................................................................................... 146
Simone Monesi
Chapter 13 Japan ................................................................................... 159
Reiji Takahashi, Atsutoshi Maeda, Shun Hirota
and Yuko Suzuki
Chapter 14 Malaysia ............................................................................ 171
Lukman Sheriff Alias
Chapter 15 Mexico ............................................................................... 179
Gonzalo A Vargas
Chapter 16 Netherlands ................................................................. 190
Jan Erik Janssen and Martha Brinkman
Chapter 17 Nigeria ............................................................................... 199
Ken Etim and Ayodele Oni
Chapter 18 Norway .............................................................................. 210
Per Conradi Andersen and Christian Poulsson
Chapter 19 Russia .................................................................................. 219
Evgeny Danilov
Chapter 20 South Africa .................................................................. 237
Shamilah Grimwood and Zahra Omar
Chapter 21 Spain .................................................................................... 257
Antonio Morales
Chapter 22 Sweden .............................................................................. 266
Hans Andréasson, Martin Gynnerstedt and Malin Håkansson
Chapter 23 Switzerland .................................................................. 278
Georges P Racine
Chapter 24 Turkey ............................................................................... 290
Zeynel Tunç
vi

Contents
Chapter 25 United Arab Emirates ................................................ 302
Masood Afridi and Haroon Baryalay
Chapter 26 United Kingdom .......................................................... 319
Elisabeth Blunsdon
Chapter 27 United States ................................................................ 334
Michael J Gergen, Natasha Gianvecchio and David L Schwartz
Chapter 28 Venezuela........................................................................ 344
Arnoldo Troconis
Appendix 1 About the authors .................................................... 357
Appendix 2 Contributing Law Firms’ contact details ..... 374
vii

Editor’s Preface
Safe and reliable delivery of electricity and natural gas has been the hallmark of energy
policy and regulation in the industrialised world for the past 75 years. More recently,
regulators, policymakers and the industry began to focus their attention on ways to
improve economic efficiency, increase productivity and reduce costs through a seemingly
endless series of reforms.
In some countries, utilities were encouraged to enhance transmission and
interconnection facilities with neighbouring systems in order to pool energy resources.
More recently, utilities have been encouraged to participate in regional organisations to
buy and sell power, and to administer transmission, dispatch and scheduling of a variety
of energy products. Certain countries have encouraged utility efficiency through a variety
of performance-based incentives.
Policymakers have tried to reduce the barriers to entry by requiring
non‐discriminatory treatment among transmission users, and prohibiting affiliate abuse.
Utilities were encouraged to unbundle certain utility services; in some cases, regulators
required the divestiture of generation or transmission facilities. Utilities have even been
encouraged to provide retail wheeling services to facilitate competition for delivery
service customers.
Many markets have developed competitive bid-based electricity auctions to set
energy and capacity prices, which often take into consideration the cost of transmission
congestion. These markets tend to be administered by independent or governmental
entities that do not have a market position bias. Clearing prices set in these markets are
intended to send price signals to maximise short-term efficiency (scheduling, dispatching
and selling energy), as well as long-term efficiency (building new or retiring old generation
and transmission facilities).
In certain countries, lawmakers and policymakers have encouraged developers
to build and finance new renewable resources and to develop more effective means
of conserving energy, through a variety of ‘carrots’ and ‘sticks’. These measures have
included subsidies such as feed-in tariffs and renewable energy credits, as well as utility
ix

Editor’s Preface
requirements through renewable portfolio standards. In certain competitive markets,
conserving electricity has been converted into a demand-side product (‘negawatts’) with
near or equal value to supply-side generation (megawatts). New ‘smartgrid’ technologies
have been created to increase the efficiency of transmission, generation, distribution and
individual consumers’ energy use.
Now, however, the myriad of efficiency mechanisms faces new and unprecedented
challenges. Transmission and distribution systems are ageing and desperately need
upgrading. Severe new environmental requirements are leading to mass retirements of
baseload coal-generation resources. Fuel prices are volatile, adding long-term uncertainty
to energy prices. Spikes in the price of raw materials are making the development of
new infrastructure all the more expensive. Cyber-security threats are exposing the
vulnerabilities of our energy networks. And the global economy continues to threaten
our ability to obtain the necessary credit to build and finance energy infrastructure.
This is the sobering backdrop for this inaugural edition of The Energy Regulation
and Markets Review. I would like to thank all of the authors for their thoughtful
consideration of these difficult challenges. As can be seen in these chapters, we have
much to consider and resolve before we can achieve the kinds of energy security and
efficiency that we have been pursuing.
David L Schwartz
Latham & Watkins LLP
Washington, DC
June 2012
x

Chapter 1
Australia
Mitzi Gilligan, Eliza Bartlett, Carolyn Vigar, Darshini Nanthakumar,
Rudi Kruse, Genevieve Watt and Nicholas Liau 1
I
OVERVIEW
In order to understand the regulation of energy industries and the energy markets in
Australia, it is important to first understand the political and regulatory system in which
they operate.
Australia is a federation of six states. Legal and political power is divided between
the federal government and the state governments in accordance with the Federal
Constitution.
The Federal Constitution confers power on the federal parliament to legislate
for specific matters, including taxation, foreign investment, the banking and monetary
system, and interstate and overseas trade. The states retain the power to legislate for all
other matters.
The six states forming the federation are Queensland, New South Wales (‘NSW’),
Victoria, Tasmania, South Australia and Western Australia. The federal government
created the Australian Capital Territory (‘ACT’) and the Northern Territory as politically
autonomous legislatures under its legal control.
Each Australian state and territory has the power to make laws with respect to its
electricity and gas industries. Consequently, the regulation of each state and territory’s
electricity and gas industries originally developed separately.
Significant reform has occurred in Australian energy markets in recent years.
The states of Queensland, NSW, Victoria, Tasmania and South Australia and the ACT
have combined to form a single interconnected National Electricity Market (‘NEM’),
which operates under a largely consistent legal and regulatory framework within the
participating jurisdictions. The NEM is a wholesale market for the supply and purchase
1 Mitzi Gilligan is a partner, Eliza Bartlett is a senior associate, Carolyn Vigar is a special counsel,
Darshini Nanthakumar, Rudi Kruse, Genevieve Watt are lawyers and Nicholas Liau is a
graduate at Minter Ellison.
1

Australia
of electricity combined with an access regime to enable connection to the transmission
and distribution networks in the participating jurisdictions.
The key features of the NEM are as follows:
a electricity is predominantly traded through a centralised pool (spot market).
Generators bid to supply electricity at prices of their choice and are dispatched in
increasing bid price order; the price they receive is the pool clearing price for each
30-minute trading interval;
b
c
wholesale purchasers buy their electricity requirements from the pool; and
charges for use of network assets are separate from the pool price for electricity
paid to generators.
The electricity networks making up the NEM stretch more than 45,000 kilometres from
Cairns in Queensland to Port Lincoln in South Australia and Hobart in Tasmania.
NEM participants may enter into financial hedge contracts (contracts for
differences) to manage their exposure to pool price fluctuations. These contracts operate
independently of the NEM, establishing a set price for electricity that will be obtained or
consumed at a particular time. While not regulated by the NEM, these contracts may be
subject to other requirements, such as financial services licensing.
A wholesale gas trading market exists in Victoria and a short-term trading market
operates in each of Sydney, Adelaide and Brisbane. Australia’s natural gas reserves are
linked to major domestic markets by over 25,000 kilometres of high-pressure pipelines.
Australia’s gas distribution system comprises over 80,000 kilometres of local reticulated
pipelines.
II
REGULATION
i The regulators
The key energy regulator in Australia is the Australian Energy Regulator (‘the AER’). 2
The AER is responsible for the economic regulation of gas and electricity transmission
and distribution networks and for enforcing the gas and electricity laws and rules in all
jurisdictions, except for gas in Western Australia.
The AER is a part of the Australian Competition and Consumer Commission
(‘the ACCC’), 3 but it operates separately. The ACCC is responsible for administering the
Competition and Consumer Act 2010 (Cth) (‘the CCA’) and ensuring compliance with
Australia’s competition, fair trading and consumer protection laws.
Responsibility for electricity distribution pricing and access to distribution
networks was transferred from the states and territories to the AER from 1 January 2008.
Western Australia and the Northern Territory continue to regulate their own distribution
networks as they are not jurisdictions that participate in the NEM. Each state and
territory regulates technical and safety matters in respect of the electricity industry and
retains electricity rationing powers.
2 www.aer.gov.au.
3 www.accc.gov.au.
2

Australia
The regulator for Western Australia is the Economic Regulation Authority (‘the
ERA’). 4 The ERA regulates monopoly aspects of the gas, electricity and rail industries and
is responsible for providing licences to providers of gas, electricity and water services in
Western Australia. The regulator for the Northern Territory is the Utilities Commission
of the Northern Territory. 5
Other key energy regulators and bodies in Australia include the following:
a the Australian Energy Market Commission (‘the AEMC’), which is responsible
for rulemaking in relation to the economic regulation of electricity distribution
network services, gas transmission and distribution services, access to natural gas
pipeline services and other elements of broader natural gas markets, and electricity
and gas market rulemaking;
b the Standing Council on Energy and Resources (‘the SCER’), which replaced the
Ministerial Council on Energy 6 in February 2011;
c the Australian Energy Market Operator (‘AEMO’), 7 which is a single, industryfunded,
national electricity and gas market operator and network planner. Its role
includes management of the NEM and the retail and wholesale gas markets in
Victoria, NSW, the ACT, Queensland and South Australia, and overseeing system
security of the NEM electricity grid and the Victorian gas transmission network;
and
d the National Competition Council (‘the NCC’), 8 which makes recommendations
to relevant government ministers on the coverage of natural gas pipeline systems.
Separate regulators also exist in each state and territory for generation and electricity
and gas retail licensing (although this is about to change – see discussion of the NECF
below):
a in NSW, the Independent Pricing and Regulatory Tribunal; 9
b in Victoria, the Essential Services Commission; 10
c in the Northern Territory, the Utilities Commission of the Northern Territory;
d in Western Australia, the ERA;
e in Tasmania, the Economic Regulator; 11
4 www.erawa.com.au.
5 www.nt.gov.au/ntt/utilicom/electricity/.
6 The Ministerial Council on Energy comprised federal, state and territory energy ministers,
was the national policy and governance body for electricity and gas. It had the power to issue
statements of policy principle to the AEMC and to direct reviews by the AEMC with respect
to rulemaking and market development; www.mce.gov.au.
7 www.aemo.com.au.
8 www.ncc.gov.au.
9 www.ipart.nsw.gov.au.
10 www.esc.vic.gov.au.
11 www.economicregulator.tas.gov.au.
3

Australia
f in Queensland, the Director-General of the Department of Employment,
Economic Development and Innovation; 12
g in South Australia, the Essential Services Commission of South Australia; 13 and
h in the ACT, the Independent Competition and Regulatory Commission. 14
Legal framework
The legal framework in Australia for the regulation of both electricity and gas industries
consists of:
a the National Electricity Law (‘the NEL’) and National Gas Law (‘the NGL’) in
participating jurisdictions;
b legislation of each state and territory;
c the National Energy Retail Law;
d legislative instruments, including the National Electricity Rules (‘the NER’) and
the National Gas Rules (‘the NGR’);
e regulations under the NEL and NGL, limited to minor processes and procedural
matters in the NEL and NGL and the prescription of civil penalties; and
f statements of policy and principle from regulators, subject to the procedures set
out in the NEL and NGL.
The NGL is contained in a schedule to the National Gas (South Australia) Act 2008 (SA).
An application statute for each participating jurisdiction governs the extent to which the
national gas legislation and national electricity legislation applies in that jurisdiction. To
date, the NGL and NEL have been adopted, in various forms, in each Australian state
and territory.
The NEL is contained in a schedule to the National Electricity (South Australia)
Act 1996 (SA). The NEL is applied as law in each participating jurisdiction of the NEM
by application statutes.
ii Regulated activities
Electricity
Unless a person is exempt or is a registered participant with respect to that activity with
AEMO, it is prohibited from:
a owning, controlling or operating a generating system connected to the NEM;
b owning, controlling or operating a transmission system or distribution system
that forms part of the NEM;
c operating or administering a wholesale exchange for electricity; or
d purchasing electricity directly through a wholesale exchange.
By registering with AEMO, a person becomes bound to comply with the NER.
12 www.business.qld.gov.au.
13 www.escosa.sa.gov.au.
14 www.icrc.act.gov.au.
4

Australia
In addition to the requirements of the NER, each state and territory currently
has its own licensing regime for electricity industry participants, such that participants
require a licence to generate, transmit, distribute or supply electricity in each state and
territory. Applicants are generally required to show they are a fit and proper person to
hold the licence, that they are in a position to meet the applicable financial and prudential
requirements, and that they have the requisite technical and operational capacity to
undertake the activities permitted under the licence. This means that electricity entities
participating in the NEM have to register as NEM participants under the NER and also
obtain any requisite electricity licence under the relevant state or territory legislation.
State and territory regulation of retail licensing is, however, set to be standardised
under the National Energy Retail Law (‘the NERL’) and Rules, which are due to
commence in the NEM jurisdictions on 1 July 2012 and which will be administered by
the AER. The NERL is part of the National Energy Customer Framework (‘the NECF’)
and is also part of the overall trend towards the centralisation of gas and electricity
regulation. Under the new laws, retailers will only need one licence to sell electricity in
NEM jurisdictions.
The NECF will introduce a consistent set of rules in each jurisdiction, however,
there is still scope for jurisdictional differences on some matters.
Gas
Unless exempt, a person is prohibited from engaging in the sale or distribution of gas
unless that person holds a licence to undertake the activity. As with electricity, licensing
for gas is regulated on a jurisdiction-by-jurisdiction basis. This means, for example, that
a gas retailer operating in Victoria, South Australia, NSW and Queensland must be
separately licensed as a gas retailer in each of those jurisdictions. As with electricity laws,
however, state-based regulation of the gas industry will soon be standardised under the
NECF, meaning that gas retailers in the national gas market jurisdictions will only need
to hold one licence to operate in each of those jurisdictions.
For onshore and offshore petroleum activities, a person also requires the following
authorisations:
a an exploration permit in order to carry out petroleum exploration;
b a production licence in order to produce petroleum from a specified licensed area;
and
c a licence in order to construct or operate a gas pipeline.
Process
AEMO is responsible for the registration of participants in energy markets operated by
AEMO. These are the markets regulated under the NEL and NGL.
Applicants must also submit their licence applications to the relevant state
regulator where required.
iii Ownership and market access restrictions
Foreign investment restrictions
Foreign investment in Australia is regulated by the Foreign Investment Review Board
(‘the FIRB’). International investors must apply to the FIRB to acquire a ‘substantial
5

Australia
interest’ in an Australian company, generally taken to be 15 per cent or more of such a
company. This requirement only applies if the value of the company to be acquired is
greater than A$244 million, or A$1.06 billion for US investors. If the investment flows
from a foreign government, then no monetary guidelines apply. Once conduct is notified
to the FIRB, the FIRB will consider the proposed conduct but may disallow it if the
FIRB determines the investment is against the Australian ‘national interest’.
Competition restrictions
The CCA prohibits acquisitions of shares or assets that have the purpose or actual or
likely effect of substantially lessening competition in a market. This applies to both
foreign investment and to the transfer of control or assignment of assets by or to domestic
companies (see below).
In addition, in Victoria there are cross-ownership rules under the Electricity
Industry Act 2000 (Vic) and the Gas Industry Act 2001 (Vic), which restrict the degree to
which operators in the electricity or gas industries can own a business in a different sector
of the supply chain. For example, the relevant provisions of the Electricity Industry Act
are designed to prevent a transmission, generation or distribution licensee from holding
a controlling interest in another kind of licensee, or from holding a substantial interest in
two or more licensees. The restrictions under both Acts may be waived where the ACCC
does not consider that the acquisition would substantially lessen competition in breach
of the Australian Consumer Law. The Bill currently before the Victorian Parliament for
the introduction of the NERL in Victoria seeks to repeal the cross-ownership restrictions.
iv Transfers of control and assignments
Within the energy industry, merger controls represent a significant barrier to the purchase
of new assets. The ACCC has expressed concerns about the accumulation of market
power by merger in the electricity sector and about the potential anti-competitive effects
of vertical integration in the sector.
The ACCC administers and enforces the merger provisions under the CCA. There
are three main ways a proposed acquisition or merger may be assessed under the CCA:
a informal clearance – the ACCC may give an informal view on whether a
particular proposal is likely to breach the competition provisions of the CCA
and, by implication, whether the ACCC would challenge the proposal;
b formal clearance – the ACCC may grant clearance to a proposal if it is satisfied
that the proposal would not have the effect or likely effect of substantially
lessening competition in a market or markets. Clearance may be conditional or
unconditional; and
c authorisation by the Australian Competition Tribunal – the Australian
Competition Tribunal may grant an authorisation for a proposal if it is satisfied in
all the circumstances that the proposal would result or is likely to result in such a
benefit to the public that the proposal should be allowed to occur even though the
proposal may have the purpose or actual or likely effect of substantially lessening
competition in a market.
Clearance can take up to three months.
6

Australia
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
There has been a trend towards the separation of transmission from the production and
retail sectors, with energy industry operators generally specialising in either network
infrastructure, including transmission, or the non-network areas of production,
generation and retail. This trend has been linked to capital markets and the limited
efficiency benefits of full-scale integration. It also reflects national competition policy
pursued by the Commonwealth, state and territory governments in the 1990s.
There has, however, tended to be greater integration and ownership consolidation
within each sector. The ACT, South Australia and Tasmania have only one major
electricity distribution network each, and while there are multiple networks in
Queensland, NSW and Victoria, each is a monopoly provider in a particular area.
Cheung Kong Infrastructure and Power Assets Holdings, for example, jointly own 51
per cent of two Victorian distribution networks, as well as holding a 200-year lease of the
South Australian distribution network. In both states, the other 49 per cent is owned by
Spark Infrastructure, in which Cheung Kong Infrastructure has a direct interest. 15
The distribution and transmission sectors are not generally integrated. In Tasmania
and the ACT, there is some common ownership in the distribution and retailing sectors. 16
There is a mix of both government-owned and privately owned distribution or retail
businesses, with a trend to privately owned utilities in all states and territories:
a the transmission network and the five distribution networks in Victoria are
privately owned;
b the transmission and distribution networks in South Australia are leased to private
interests;
c the transmission and distribution networks in the ACT have joint government
and private ownership; and
d the transmission and distribution networks in Queensland, NSW and Tasmania
are government-owned.
There has been a trend towards vertical integration of generation and retail activities, a
trend sometimes referred to as ‘gentailing’. There is an acceptance in the industry that
‘gentailing’ enables generators or producers and retailers to manage the risk of volatile
wholesale prices and to enhance security of supply. Gas and electricity are also increasingly
being marketed jointly, with customers being able to obtain dual supply under a single
contract. AGL Energy, TRUenergy and Origin Energy now jointly supply more than 80
per cent of small electricity retail customers, and control almost 30 per cent of generation
capacity in the mainland regions of the NEM. Similarly, those entities each have interests
in gas production or gas storage, or both.
15 AER, State of the Energy Market 2011, available at www.accc.gov.au,
16 Id.
7

ii
Australia
Transmission/transportation and distribution access
Electricity
The NER sets out a regime that enables generators to connect generation equipment
to the national grid. Transmission and distribution network operators are obliged to
connect generators’ equipment, as long as certain conditions are met. For example, a
generator’s equipment must meet certain technical standards before it can be connected
to the grid. The network operator is required to consult with AEMO about the technical
requirements of connecting a generator’s equipment, and any changes to the network
that may need to be made to accommodate that equipment.
Gas
The NGL and NGR set out a ‘coverage’ process, which determines whether a gas pipeline
should be subject to mandated third-party access arrangement and in what form.
The NCC must recommend that the pipeline be covered if the NCC is satisfied
that the following ‘coverage criteria’ are met:
a that access (or increased access) to services provided by the pipeline would promote
a material increase in competition in another market or markets (whether or not
in Australia);
b that it would not be economical to develop another pipeline to provide the same
services;
c that access (or increased access) to the services provided by the pipeline can be
provided without undue risk to human health or safety; and
d that access (or increased access) to the services provided by the pipeline would not
be contrary to the public interest.
In making a coverage determination, the NCC must also bear in mind the national
gas objective, which is to promote efficient investment in, and operation of, electricity
services in the long-term consumer interest.
Typically, a pipeline will be covered where a monopoly exists on its particular
transmission route. Since the early 2000s, increased investment in gas transmission
pipelines around Australia has increased competition between pipeline operators,
resulting in fewer pipelines being covered under the law.
Pipelines that are not covered are subject only to the general competition law
provisions of the CCA and third-party access to them is a private matter between the
pipeline owner or operator and the access seeker. Accordingly, operators of uncovered
pipelines may negotiate freely with access seekers without regulatory interference.
Alternatively, a form of ‘light regulation’ applies in some circumstances with a low level
of regulatory intervention that does not include setting tariffs.
iii Rates
Electricity
Regulated transmission businesses must periodically submit revenue proposals, together
with a proposed pricing methodology and negotiating framework, to the AER (typically,
every five years). The pricing methodology is a formula for the business to allocate its
revenue allowance and determine the prices it may charge for its services.
8

Australia
The AER’s regulatory approach involves determining a revenue cap for each
transmission business, which is the maximum revenue a business can earn during the
regulatory period. The AER applies a building block model to determine the revenue
that a transmission business needs to cover its efficient costs and a commercial return to
the business. The building blocks cover:
a operational and maintenance expenditure;
b capital expenditure;
c asset depreciation costs;
d taxation liabilities; and
e a commercial return on capital.
The AER will also determine whether a service target performance incentive scheme
(service standards scheme) or efficiency benefit-sharing scheme will apply to that
business:
a an ‘efficiency benefit-sharing scheme’ encourages transmission businesses to
achieve efficient operating and maintenance expenditure in running their
networks by sharing efficiency gains between businesses and customers (through
lower prices); and
b a ‘service target performance incentive scheme’ encourages businesses to maintain
or improve network service performance and thus balances the efficiency benefitsharing
scheme so businesses do not reduce costs at the expense of service quality.
The regulatory framework for distribution businesses is similar to the framework for
transmission businesses but there are differences. In particular, where the AER is the
regulator (state and territory regulators in Western Australia and the Northern Territory
still regulate distribution businesses in those jurisdictions), the process commences when
the AER releases a draft framework approach for a network.
Unlike transmission businesses, which must all be subject to a revenue cap,
distribution businesses must be subject to some form of control mechanism, but the
AER may choose the form of incentive. In addition to revenue and price caps, the
following approaches are available in Australia and have been used by regulators in some
of the jurisdictions or networks:
a revenue yield models, which link the revenue a business may earn to the volume
of electricity sold;
b weighted average price caps, which set a ceiling on distribution prices but allow
flexibility in individual tariffs within that ceiling; and
c schedule of fixed price caps, whereby a list or schedule of prices is set for each
individual service that the business provides.
When using any of the above control mechanisms, the AER is also required to forecast
the revenue requirement of the business over the regulatory period. This is achieved using
a building block model, with building blocks covering:
a investment forecasts;
b the operating expenditure allowances that a benchmark distribution business
would require if operating efficiently;
c asset depreciation costs;
9

Australia
d
e
a commercial return on capital; and
taxation liabilities.
Gas
The NGL applies nationally to Australian gas pipeline operators – both transmission
pipelines and distribution networks. Pipelines that are ‘covered’ under the law are subject
to set pricing regimes, determined by the AER. When determining the pricing regime
to apply to each gas pipeline, the AER will take into account the same factors as are
outlined above for electricity transmission rates.
iv Security and technology restrictions
AEMO is responsible for managing system security of the NEM electricity grid and
the Victorian gas transmission network. AEMO manages the market and power system
from two control centres, each of which is in a different state. The entire NEM can be
operated from one or both centres. This means that in the event of a natural disaster or
other emergency, continuous supply can be ensured.
If a critical supply shortfall occurs because system security or reliability of supply is
threatened, AEMO has a range of powers under the NER to restore supply and demand
balance, including:
a demand side management;
b the power to direct generators to produce energy when a supply shortfall is
expected;
c the power to instruct network service providers to shed customer load (only
permitted when there is an urgent need to protect the power system by reducing
demand); and
d tender for contracts for electricity supply from sources such as emergency
generators and other generators connected to the distribution network, who are
not usually factored into AEMO’s forecasting process.
The states and territories also have reserve emergency powers under legislation to take
over and prioritise the use of the utilities in emergency situations. In Queensland, for
example, the Gas Supply Act 2003 (QLD) gives the relevant state minister power to
regulate the supply, distribution and sale of gas to customers in the event of a shortage
of gas supply.
IV
ENERGY MARKETS
i Development of energy markets
Electricity
Each Australian state and territory has the power to make laws with respect to its
electricity industry. Consequently, each state’s and territory’s electricity industry originally
developed separately, and each operated a vertically integrated electricity industry. Major
reforms in Australia’s electricity markets since the 1990s have radically altered this model.
10

Australia
While there remain jurisdictional differences in the structure and regulation of
the electricity industries in each Australian state and territory, all Australian states and
territories have now restructured their respective electricity industries, generally to:
a separate the electricity service providers into distinct generation, transmission,
distribution and retail supply entities;
b remove the responsibility for performing regulatory functions from the electricity
service providers; and
c introduce competition into the generation and retail supply sectors.
Under the NEL and NER, AEMO administers a spot market for the wholesale supply
and purchase of electricity, operated through a central pool. Generators make offers every
five minutes to supply the market with a set amount of electricity at a certain price. Based
on these offers, AEMO decides which generator is required to produce electricity to meet
the current demand at the best price. The selected generators are then dispatched into
production, and a dispatch price is set every five minutes. The spot price for each trading
interval is set by averaging the six dispatch prices given each half hour (in five-minute
intervals), within a maximum and minimum (floor) spot price. This is done for each
region in the NEM.
Gas
Victoria established a wholesale spot market in 1999 to manage gas flows on the Victorian
transmission system and to allow market participants to buy and sell gas at spot prices.
More recently, the National Gas Market Bulletin Board (‘the BB’) and short-term trading
markets in major hubs (Sydney, Adelaide and Brisbane) have also been established.
In the Victorian wholesale spot market, participants submit daily bids ranging
from $0 per gigajoule to $800 per gigajoule. Bids may be revised at designated scheduling
intervals during the day. At the beginning of each day, AEMO stacks supply offers and
selects the least-cost bid to match demand in the market (the clearing price). AEMO
can also schedule additional gas injections (typically liquefied natural gas or ‘LNG’) at
above-market price to alleviate short-term constraints. Approximately 10–20 per cent
of wholesale gas volume is traded on the spot market. The remaining gas is sourced via
contracts or vertical ownership between producers and retailers.
The short-term trading market was launched in September 2010 in Sydney and
Adelaide and was extended to Brisbane in December 2011. The hubs link transmission
pipelines and distribution systems. Each hub is scheduled and settled separately but
each operate under the same rules. The market sets a daily ex ante clearing price at each
hub, based on scheduled withdrawals and day-ahead offers by gas shippers to deliver gas.
Participants may buy some or all of their gas requirements on a spot basis.
The BB, which commenced in July 2008, is a single electronic communications
system (website) covering all major gas production fields, major demand centres and
natural gas transmission pipeline systems of South Australia, Victoria, Tasmania, NSW,
the ACT and Queensland.
The BB aims to facilitate trade in gas and capacity over the relevant pipeline
systems through the provision of real-time system and market information. It covers:
a supply-demand outlook (including forecast pipeline flows, capacity outlook and
linepack capacity adequacy);
11

Australia
b
c
actual flow data; and
standing data (including standing capacities and standing peak day demand
forecasts).
ii Energy market rules and regulation
Electricity
The NEL and the NER provide the framework for the operation of the NEM.
The NER sets out detailed rules for the operation of the spot market, power system
security, access to electricity networks, connection to networks and methods to be used
for pricing network services. It also defines the responsibilities of market participants.
Gas
The NGL and NGR provide a national framework for the regulation of gas transmission
and distribution networks, as well as for the gas and electricity trading markets. The
NGL and NGR replace the old Gas Pipelines Access Law and the National Gas Code.
iii Contracts for sale of energy
Price regulation
Each state and territory, except Victoria, applies some form of retail electricity price
regulation. Price caps are set so that retailers can:
a recover the costs that each state regulator considers an ‘efficient’ retailer would
incur; and
b make a ‘reasonable’ margin (ranging from 3 to 10 per cent).
State and territory governments are currently reviewing their use of retail price caps and
have agreed to remove them where effective competition can be demonstrated.
Consumer unfair contract terms
Consumer energy contracts are also subject to the unfair contracts regime set out in the
CCA. Under the unfair contracts regime, an ‘unfair’ term in a standard form consumer
contract will be unenforceable. Further, a court can injunct a supplier from relying on a
particular term. A term will be ‘unfair’ if:
a it causes a significant imbalance in the parties’ rights and obligations arising under
the contract;
b it is not reasonably necessary in order to protect the legitimate interests of the
party who would be advantaged by the term; and
c it would cause detriment (whether financial or otherwise) to a party if it were to
be applied or relied on.
The NECF
The NECF also contains a range of consumer protections, including the making of model
terms and conditions for standard retail customers that gas and electricity retailers must
adopt. If a retailer’s retail contract is inconsistent with the model terms and conditions,
the retail contract has no effect to the extent of that inconsistency.
12

iv
Market developments
Australia
AEMC priorities
In 2011, the AEMC undertook an assessment of the Australian stationary energy sector,
to identify current challenges and to develop a set of key priorities for the development of
this sector. On the basis of this review, the AEMC developed three key strategic priorities:
a creating a predictable regulatory and market environment for rewarding
economically efficient investment;
b
c
building the capability and capturing the value of flexible demand; and
ensuring the regulation of transmission and distribution networks promotes
timely investment and efficient outcomes. 17
The challenges identified included the interaction between the gas market and the NEM
as a result of growth in gas-fired electricity generation, which may lead to vulnerability
of the NEM to gas supply shortages. The AEMC also identified significant future
investment requirements to improve transmission networks throughout the NEM.
Significant investment in low emissions intensity generation capacity will also
be required to address climate change policy such as the carbon emissions pricing and
the Renewable Energy Target (‘RET’) under the Australian Government’s Clean Energy
Future Plan. Climate change policy is also predicted to produce an increase in wind
generation and gas plant, which could lead to greater spot price volatility, potentially
affecting the resilience of energy markets. The AEMC has predicted that, as a result
of this, generators and retailers may change their financial risk management strategies.
Mechanisms will also need to be established to limit the extent of disruption of the
market as a whole if individual participants experience financial hardship. 18
Liquefied natural gas and coal seam gas
In addition to Australia’s national gas reserves, Australia also has substantial reserves of
coal seam gas (‘CSG’) in both NSW and Queensland. This, together with long-term
projections of rising international energy prices, has spurred the development of several
Liquefied natural gas (‘LNG’) projects. Construction of three export LNG projects is
underway, with first CSG–LNG exports expected in late 2014. Five further proposals
are under consideration. If all current proposals are developed to full capacity, this would
represent a potential LNG export market for Queensland of more than 50 million tonnes
per annum. 19 CSG production has also reshaped the domestic market by providing a
new source of gas supply.
17 AEMC, Strategic Priorities for Energy Market Development 2011, available at www.aemc.gov.
au/Media/docs/Strategic%20Priorities%20for%20Energy%20Market%20Development%20
-%20low%20resolution%20pdf-a702b945-89b9-4d09-a8b0-7c31aa7a47de-2.PDF.
18 Id.
19 Queensland Department of Employment, Economic Development and Innovation,
Queensland’s coal seam gas overview, February 2012, available at http://mines.industry.qld.
gov.au/assets/coal-pdf/new_csg_cc.pdf.
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Australia
V
RENEWABLE ENERGY AND CONSERVATION
i
Development of renewable energy
The Australian Government’s Clean Energy Future Plan, 20 including the introduction of
the carbon price mechanism (‘CPM’) on 1 July 2012, will result in a significant boost to
the renewable energy sector in Australia. It is expected that the combined incentives from
the carbon price package and ongoing RET will accelerate the deployment of renewable
energy in Australia by driving forward around A$20 billion in investment in renewable
energy in the period to 2020. 21
In the year ending September 2011, the contribution of renewable energy rose
to 9.6 per cent of the total electricity produced during that period, up from 8.7 per cent
the year before. 22 The breakdown of renewable energy generation, by fuel source, was as
follows:
a hydro: 67.2 per cent;
b wind: 21.9 per cent;
c bioenergy: 8.5 per cent;
d solar PV: 2.3 per cent;
e solar thermal: 0.015 per cent;
f marine: 0.003 per cent; and
g geothermal: 0.002 per cent.
Clean Energy Finance Corporation
The establishment of a commercially oriented A$10 billion Clean Energy Finance
Corporation (‘the CEFC’) as part of the Clean Energy Future Plan is a key policy initiative
designed to drive investment in renewable energy, energy efficiency, low-emissions
technologies and adaptation assistance for manufacturing. The object of the CEFC is to
help to overcome capital market barriers to commercialising clean energy technologies
by leveraging private sector financing. 23 The CEFC will be run independently by a board
of experts in banking, investment management and clean energy and low-emissions
technologies and is proposed to commence operating in 2013–14. 24
20 Australian government, Securing a Clean Energy Future – The Australian Government’s climate
change plan, Canberra, July 2011, available at www.cleanenergyfuture.gov.au/clean-energyfuture/our-plan/.
21 Department of Resources, Energy and Tourism, Draft Energy White Paper 2011: Strengthening
the foundations for Australia’s energy future, Canberra, December 2011, available at www.ret.
gov.au/energy/Documents/ewp/draft-ewp-2011/Draft-EWP.pdf.
22 Clean Energy Council, Clean Energy Australia Report 2011, November 2011, available at www.
cleanenergycouncil.org.au.
23 Australian government, Financing Clean Technologies, www.cleanenergyfuture.gov.au/cleanenergy-future/our-plan/clean-energy-australia/financing-clean-technologies/.
24 Australian government, 12 October 2011, Clean Energy Finance Corporation: experts appointed,
available ar www.cleanenergyfuture.gov.au/clean-energy-finance-corporation-experts-appointed/.
14

Australia
Australian Renewable Energy Agency
Another component of the Clean Energy Future Plan is the establishment of the Australian
Renewable Energy Agency (‘ARENA’) under the Department of Resources, Energy and
Tourism on 1 July 2012. 25 ARENA is to be an independent statutory body that will
administer A$3.2 billion in funding to support renewable energy technology development,
including research, development, demonstration, deployment and commercialisation
across technologies such as solar (including large-scale solar), biomass, biofuels, ocean and
geothermal. A$1.5 billion is already committed to existing projects from programmes and
initiatives that will be consolidated into ARENA, while the remaining A$1.7 billion of
funding is currently uncommitted and will be available for ARENA to provide early-stage
grants and financing assistance for renewable energy projects. 26 Furthermore, ARENA is
responsible for developing skills in the renewable energy industry and promoting knowledge
sharing and collaboration on renewable energy technology innovation with Australian and
international governments and institutions. 27
Renewable energy target
As mentioned above, the RET will continue in operation once the CPM is in effect.
The RET is established under the Renewable Energy (Electricity) Act 2000 (Cth) and
is designed to ensure that by 2020, renewable generation accounts for 20 per cent of
overall electricity generation. Since January 2011, the existing RET scheme has operated
in two parts: the Small-scale Renewable Energy Scheme and the Large-scale Renewable
Energy Target.
The RET requires electricity retailers to acquire and surrender a certain number of
renewable energy certificates (‘RECs’) as an incentive to bridge the gap between the price
of green energy and the price of black energy. The number is determined as a proportion
of the retailer’s overall acquisitions of electricity. Following changes to the RET that
commenced on 1 January 2011, there are now two forms of RECs that retailers can
purchase to satisfy their liability:
a large-scale renewable energy certificates, which can be created by accredited
renewable energy power stations (e.g., wind farms and large solar installations);
and
b small-scale technology certificates, which are created from small units (e.g., solar
PV panels and solar water heaters).
25 Australian Renewable Energy Agency Act 2011 (Cth).
26 Department of Resources, Energy and Tourism, Draft Energy White Paper 2011: Strengthening
the foundations for Australia’s energy future, Canberra, December 2011, available at www.ret.
gov.au/energy/Documents/ewp/draft-ewp-2011/Draft-EWP.pdf.
27 Martin Furguson (Minister for Resources and Energy and Minister for Tourism) and Greg
Combet (Minister for Climate Change and Energy Efficiency), 12 October 2011, media
release: Legislation introduced to establish ARENA, www.climatechange.gov.au/~/media/Files/
minister/combet/2011/media/october/mr20111012.pdf.
15

Australia
Prior to the amendments to the RET, Australian states and territories had similar measures
in place. These state-based schemes have since been superseded by the national RET.
ii
Energy efficiency and conservation
National Energy Savings Initiative
Various Australian states have implemented energy efficiency certificate schemes (e.g.,
the Victorian Energy Efficiency Target scheme, or ‘VEET’, the New South Wales Energy
Savings Scheme, or ‘EES’). Under schemes of this kind, liability is imposed on electricity
(and in some cases, gas) retailers in a similar manner to that described above for the RET.
These retailers acquit their liability by purchasing and surrendering energy efficiency
certificates, which can be generated for certain eligible energy efficiency activities, such
as retrofitting lights and other appliances, or on the purchase of eligible energy-efficient
appliances.
In 2009 the Australian government established the Prime Minister’s Task Group
on Energy Efficiency to report on options to deliver a step change in energy efficiency in
Australia by 2020. The Task Group’s report recommended that ‘the government agree to
the introduction of a transitional national energy savings initiative (‘NESI’) to replace
existing and planned state energy-efficiency schemes, subject to detailed consultation
on its design’. 28 In response and as part of its Clean Energy Future Plan, the Australian
government has established a NESI working group which released an issues paper inviting
submissions from the public on the design and implementation of a NESI in December
2011. 29 Subject to further analysis and consideration of responses to the issues paper,
economic modelling and a regulatory impact study to be conducted in the latter part
of 2012, the Australian government will make a final decision on whether to establish
a NESI. Establishment of a NESI will also be conditional on the endorsement of the
Council of Australian Governments and agreement that existing state schemes will be
folded into any national scheme. 30
The Energy Efficiency Opportunities Act 2006 (Cth) (EEO Act)
The Energy Efficiency Opportunities Act 2006 (Cth) (EEO Act) came into force on
1 July 2006 as a result of an initiative first announced in the federal government’s
28 Australian government, ‘Report of the Prime Minister’s Task Group on Energy Efficiency’,
Canberra, July 2010, p. 3, available at www.climatechange.gov.au/~/media/submissions/pmtaskforce/report-prime-minister-task-group-energy-efficiency.pdf.
29 Australian government, issues paper: ‘National Energy Savings Initiative’, Canberra, December
2011, available at www.ret.gov.au/energy/Documents/energy-efficiency/energy-savings/Issuespaper.pdf;
for more information see www.climatechange.gov.au/government/initiatives/energysavings-initiative.aspx.
30 Australian government, Securing a Clean Energy Future – The Australian Government’s climate
change plan, Canberra, July 2011, available at www.cleanenergyfuture.gov.au/clean-energyfuture/our-plan/.
16

Australia
2004 White Paper, ‘Securing Australia’s Energy Future’. 31 The EEO Act is aimed at
encouraging energy efficiency in the estimated 250 Australian businesses using more
than 0.5 petajoules of energy per year (large energy users).
The EEO Act requires large energy users to undertake a detailed energy assessment
and publicly report on identified opportunities that have payback periods of four years
or less. This provides a rich source of comparative data that can assist in identifying
common points of saving and provides business‐specific information for potential
energy-efficiency investments. 32
As part of its carbon price package, the government has announced that it will
expand the existing programme by extending base funding to 30 June 2017, including
energy transmission and distribution networks, major greenfield and expansion projects,
enhancing assessment and verification requirements and by establishing a voluntary
scheme for medium-sized energy users. 33
iii Technological developments
The Australian government has committed up to A$17 billion in funding to support
the development, commercialisation and deployment of clean energy technologies. This
includes the establishment of the CEFC and ARENA, as well as support for large-scale
carbon capture and storage demonstration. 34
Carbon capture and storage
Australia is one of the first countries to have established regulatory frameworks specifically
for carbon capture and storage (‘CCS’) activities. Under the framework, offshore CCS
activities in waters administered by the Federal Government will be governed by the
Offshore Petroleum Amendment (Greenhouse Gas Storage) Act 2008 (Cth), while
onshore CCS activities and those in state waters are regulated by separate state regimes.
The Australian government funds the Carbon Capture and Storage Flagships
Program, which supports the construction and demonstration of large‐scale integrated
CCS projects. Additional government support for technological development in CCS is
provided via the A$315 million Global Carbon Capture and Storage Institute and the
A$370 million National Low Emissions Coal Initiative. 35
31 Australian government, ‘Securing Australia’s Energy Future’, Canberra, June 2004, available at
www.efa.com.au/Library/CthEnergyWhitePaper.pdf.
32 Department of Resources, Energy and Tourism, Draft Energy White Paper 2011: Strengthening
the foundations for Australia’s energy future, Canberra, December 2011, available at www.ret.
gov.au/energy/Documents/ewp/draft-ewp-2011/Draft-EWP.pdf; for further details see www.
ret.gov.au/energy/efficiency/eeo/about/Pages/default.aspx.
33 Department of Resources, Energy and Tourism, Draft Energy White Paper 2011: Strengthening
the foundations for Australia’s energy future, Canberra, December 2011, available at www.ret.
gov.au/energy/Documents/ewp/draft-ewp-2011/Draft-EWP.pdf.
34 Id.
35 Id.
17

Australia
In Australia, several large-scale projects are under development, including the
Gorgon LNG project, which will commence operations in 2015 and is set to be the
world’s largest CO 2
storage project, 36 with an estimated 125 million tonnes of carbon
dioxide to be injected under Barrow Island off the north-west coast of Western Australia. 37
Another significant project is the Callide Oxyfuel Project headed by CS Energy
at the Callide Power Station in Biloela, Queensland, 38 which is designed to demonstrate
oxyfuel combustion capture technology retrofitted to an existing Australian coal-fired
power plant and to research how such technology may be applied to new power stations,
as well as demonstrating geological carbon storage.
A variety of other developments and research projects have also commenced,
including the Cooperative Research Centre for Greenhouse Gas Technologies
(‘CO2CRC’) Otway Project involving an operational CO 2
storage pilot project in the
Otways in South-Western Victoria, Delta Electricity’s post-combustion CO 2
capture
pilot plant at Munmorah Power Station on the NSW central coast and CO2CRC’s precombustion
pilot-scale capture project under which CO 2
emissions are being captured
from HRL Ltd’s research gasifier in Mulgrave, Victoria. 39
Solar energy
Although Australia has the highest average solar radiation per square metre of any
continent in the world, its large-scale solar industry is still in its formative years. 40
Presently, Australia’s largest solar plant is a 3MW facility at Liddell in NSW that utilises
solar thermal concentrators. The nation’s largest solar photovoltaic plant is a 1.2MW
facility at the University of Queensland’s St Lucia campus. 41
In order to boost technological development in solar energy the Australian
government has introduced the Solar Flagships Program (to be consolidated into ARENA),
which will provide A$1.48 billion to support the construction and demonstration of
large-scale, grid connected, solar power stations in Australia. In February 2012, the
programme was re-opened and the government has sought updated applications from
the four applicants that were shortlisted following round 1.
36 Id.
37 Shell Australia, see www.shell.com.au/home/content/aus/aboutshell/who_we_are/shell_au/
operations/upstream/.
38 Australian Coal Association, NewGenCoal, Australia, www.newgencoal.com.au/active-projects_
flagship-projects.aspx?view=13, also see www.callideoxyfuel.com/What/CallideOxyfuelProject.
aspx.
39 Australian Coal Association, NewGenCoal, Australia, www.newgencoal.com.au/activeprojects_other-australian-projects.aspx.
40 Clean Energy Council, Clean Energy Australia Report 2011, Victoria, November 2011, available
at http://cleanenergyaustraliareport.com.au/data-sheets/.
41 Id.
18

Australia
Geothermal
Geothermal energy is another focus area for technological development through the
Emerging Renewables Program and Renewable Energy Demonstration Program (both
to be consolidated into ARENA). As of 2011 only one Australian commercial geothermal
plant with an installed capacity of 0.12MW and owned by Ergon Energy was operating
in Birdsville, Queensland. However, other projects are under development. 42
Smart Grid, Smart City trial
Under the Australian government’s National Energy Efficiency Initiative – Smart Grid,
Smart City, Energy Australia, and its consortium partners (IBM Australia, GE Energy
Australia, AGL Energy, Sydney Water, Hunter Water Australia, and Newcastle City
Council) are deploying Australia’s first commercial-scale smart grid demonstration project,
based in Newcastle, NSW. 43 The A$100 million initiative aims to result in nationwide
advances in energy management by gathering comprehensive information about the costs
and benefits of smartgrids to inform future decisions by government, electricity providers,
technology suppliers and consumers across Australia. 44 Smart meters are also currently
being rolled out to residential and small business electricity customers across Victoria. 45
VI
THE YEAR IN REVIEW
Carbon
The most significant legislative change for the Australian energy sector in the 2011–12
financial year, and indeed in recent times, has been the introduction of the Clean Energy
Act 2011 (Cth) and associated legislation for the implementation of a carbon pricing
mechanism (‘the CPM’) in Australia. The object of the CPM is to reduce Australia’s
carbon emissions to 5 per cent below 2000 levels by 2020. The CPM forms part of the
Commonwealth government’s Clean Energy Future Plan and commences on 1 July 2012.
The CPM will generally impose liability on a person who has operational control
of a facility that has direct greenhouse gas emissions of 25,000 tonnes of carbon dioxide
equivalent emissions or more for a given year. The Australian government has estimated
that there will be approximately 500 entities with direct liability to acquire and surrender
eligible emissions units under the CPM.
The CPM will operate in two distinct phases:
a the fixed-charge period, which will operate from 1 July 2012 for the first three
financial years of the scheme; and
b the flexible-price period, which will operate from 1 July 2015 onwards.
42 See www.ret.gov.au/energy/clean/acre/redp/Pages/default.aspx.
43 Australian government, 2011, Department of Resources, Energy and Tourism, Australia, www.
ret.gov.au/energy/energy_programs/smartgrid/Pages/default.aspx.
44 Department of Resources, Energy and Tourism, Draft Energy White Paper 2011: Strengthening
the foundations for Australia’s energy future, Canberra, December 2011, available at www.ret.
gov.au/energy/Documents/ewp/draft-ewp-2011/Draft-EWP.pdf.
45 Australian Energy Regulator, Australia, www.aer.gov.au/content/index.phtml/itemId/743595.
19

Australia
During the fixed-charge period, carbon units will be available for purchase by liable
entities from the Clean Energy Regulator for a fixed price. The fixed price starts at A$23
per unit in 2012–13 and will rise by 2.5 per cent for each subsequent year of the fixedcharge
period. As the price of units is fixed during the fixed charge period, the scheme
will have an economic effect that is like a tax.
During the flexible price period, the price of units will generally be determined
by the market. Liable entities will be able to obtain these units at auctions conducted by
the Clean Energy Regulator, through secondary trading markets or, subject to certain
restrictions, from international carbon trading markets. The number of units made
available for any financial year will be determined by the overall carbon pollution cap
set for that year. During this flexible price period, the scheme will operate more like an
emissions trading scheme.
In accordance with modelling by the Commonwealth Treasury, the overall impact
of the carbon price on the Australian economy as a whole is expected to be minimal. The
economy is projected to continue to grow, with real national income growth rising an
average 1.1 per cent a year (compared with a business as usual 1.2 per cent per year to
2050); 46 however, the impact of carbon price pass-through is difficult to estimate given
the many factors at play, including local and international competition, industry support,
government assistance via the allocation of free eligible emissions units and government and
private investment in the development and commercialisation of clean energy technologies.
In addition to support provided through the CPM and the ongoing RET, the
Australian government’s commitment of up to A$17 billion in funding to support the
development, commercialisation and deployment of clean energy technologies under the
Clean Energy Future Plan is expected to fundamentally alter operational and investment
dynamics in the electricity and gas markets by shifting the generation mix towards
cleaner technologies and reducing the growth rate in electricity demand; 47 however, there
remains a level of uncertainty for investors due to the lack of bipartisan support for the
CPM and doubts surrounding the future of the Australian Labour Party remaining in
government at the next election.
Demand-side participation
Since 2007, the MCE (now superseded by the Standing Council on Energy and
Resources) has been undertaking a review of demand-side participation (‘DSP’), which
refers to the ability of energy consumers to determine the quantity and timing of their
energy consumption, in order to improve the efficiency of the NEM. The NEM has
traditionally only focused on supply-side demand. The AEMC released a report in
December 2009, after concluding a review into the barriers to DSP. The MCE in March
2011 directed the AEMC to undertake a further review of DSP in the NEM (Stage 3
DSP Review), which aims to identify market and regulatory arrangements that would
46 Treasury, Strong growth, low pollution: modelling a carbon price, Treasury, Canberra, 2011
(updated in September 2011), available at www.treasury.gov.au/carbonpricemodelling/
content/report.asp.
47 Id.
20

Australia
enable the participation of both supply participants and demand side consumers. The
Stage 3 DSP Review is due to be completed by September 2012. 48
Key decision
In Australian Energy Regulator v. Stanwell Corporation Limited, 49 the Federal Court
dismissed the action brought by the AER against Stanwell Corporation Limited for breach
of the good faith bidding obligations set out in the NER. Rule 3.8.22A requires generators
and market participants to make dispatch offers, dispatch bids and rebids in good faith.
The AER had alleged that a series of rebids made by Stanwell on 22 and 23 February 2008
were not made in good faith because they were made with the intention that if the dispatch
price did not rise sufficiently as a result of the rebid, Stanwell would make a further rebid
in an effort to increase the dispatch price. In determining whether the rebids occurred in
good faith, the court took the view that the market must be considered as a whole. It was
necessary for the AER to demonstrate, on the balance of probabilities, that the relevant
trader did not have a genuine intention to honour the bid at the time that it was made. The
decision is the first judicial consideration of the good faith bidding obligations in the NER.
NECF and NERL
As mentioned previously, another major change in the energy industry is the ongoing
introduction of the NECF. The Joint Implementation Group in 2011 consulted with
interested parties across all sectors, and received discussion papers from all affected
jurisdictions.
The key legal instrument giving effect to the NECF is the National Energy
Retail Law (South Australia) Act 2011 (‘the NERL’), which will be adopted by each
participating jurisdiction. The Bills to implement the NERL are currently being debated
in each participating jurisdiction’s parliament.
VII
CONCLUSIONS and OUTLOOK
Recent years have seen a tremendous amount of change in the energy markets in
Australia. One of the biggest challenges facing decision-makers is determining how to
best transition to a lower carbon energy sector. The transition will involve significant
change to how electricity and gas is generated, transported and consumed. In particular,
significant levels of new generation investment will be required to maintain reliability of
supply and to meet the objectives of the Clean Energy Future Plan.
In a report released in 2011, the AEMC identified the following key challenges
facing energy markets: 50
a rising peak demand;
b investment challenge;
48 www.mce.gov.au/dsp/default/html.
49 [2011] FCA 991, available at www.austlii.edu.au/au/cases/cth/FCA/2011/991.html.
50 AEMC, Strategic Priorities for Energy Market Development, Sydney, August 2011, available at
www.aemc.gov.au/market-reviews/completed/aemc-strategic-priorities-discussion-paper.html.
21

Australia
c
d
rising prices; and
market resilience.
In response to the aforementioned challenges, the AEMC has developed the following
strategic priorities for the further development of the stationary energy sector: 51
a a predictable regulatory and market environment for rewarding economically
efficient investment;
b building the capability and capturing the value of flexible demand; and
c ensuring the regulation of transmission and distribution networks promotes
timely investment and efficient outcomes.
The above strategic priorities will form the basis of the AEMC’s market advisory role.
51 Id.
22

Chapter 2
Austria
Bernd Rajal and Guenther Grassl 1
I
OVERVIEW
Starting from 1 October 2001, the Austrian electricity market was fully liberalised on the
basis of the European electricity directives and regulations. Whereas the tariffs for electricity
are not regulated, fixed charges apply to the transmission and distribution of electricity. The
charges are provided for in the System Charges Ordinance (SNT-VO), which is adopted
by the Austrian Energy Regulator (E-Control). The legislative competence to regulate
electricity is divided between the federal state legislature and the federal states. The federal
legislature has the authority to enact regulations on common principles of electricity
concerns whereas the federal states have the authority to regulate electricity concerns
in more detail on the basis of the federal law. The Federal Electricity Management and
Organisation Act 2010 (‘the ElWOG’) entered into force on 31 December 2011, which
transposes the EU Directive 2009/72/EC (‘the RED’) and Regulation (EC) No. 714/2009.
Currently, the vertically integrated energy companies carry out reorganisation measures
in order to comply with the new unbundling requirements (provided in the RED and
ElWOG).
The Austrian natural gas market has been fully liberalised since 1 October 2002.
The federal legislature has the authority to enact gas regulations relating to public gas
supply and gas transmission or distribution. The Gas Management Act 2011 (‘GWG
2011’) provides the regulatory framework for the national gas market. It further
contains regulations on the construction and operation of gas pipelines. Exploration and
production of natural gas is regulated under the Natural Resources Act.
The Austrian gas market currently faces material changes due to the implementation
of an entry and exit system, and a virtual gas trading point is to be established by 2013.
These measures may increase the liquidity of the Austrian gas market; however, existing
1 Bernd Rajal is a partner and Guenther Grassl is an associate at Schoenherr Attorneys at Law.
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long-term gas supply contracts, which block existing pipeline capacities, remain to be a
barrier for new market entrants.
The general energy policy of the current federal government of Austria focuses
on response to two decisive challenges: a secure, economical and social compatible
availability of energy sources and a sustainable energy supply. As a strategic framework
for measures to be taken until 2020 to tackle these challenges, and with regard to the aims
of its general work programme, the government elaborated and endorsed the Austrian
Energy Strategy (‘the AES’) in 2009. 2 The strategy shall be a comprehensive ‘energy and
climate master plan’ and thus in particular provide the national basics in order to fulfil
the respective objectives agreed at international and EU level. The main pillars of the
AES are ensuring supply security, increasing the energy efficiency and raising the share of
renewable energy sources on the total energy demand.
II
REGULATION
i The regulators
The main energy regulatory authority is E-Control, a public law institution, which is
in charge of regulating and monitoring both, the electricity market and the gas market.
The supervisory and control tasks are, inter alia, the monitoring of compliance with
competition rules and the drawing up and publishing of comparisons of electricity tariffs.
If E-Control identifies any infringements of competition rules, it may take appropriate
countermeasures. Moreover, E-Control has the authority to enact regulations (in form of
‘ordinances’) for the functioning of the Austrian electricity and gas market. The general
terms and conditions (‘GTCs’) of network operators have to be approved by E-Control.
The main sources of electricity law are the ElWOG (see Section I, supra), the
Electricity Management and Organisation Acts of the nine federal states, the Green
Electricity Act 2011 (providing a promotion scheme for the use of renewable energy
resources), the Cogeneration Act (which promotes cogeneration plants (combined heat
and power)), the High Voltage Current Line Act 1968, and the Energy Control Act 2010
(regulating the tasks and powers of the energy regulatory authority).
The main sources of gas law are the GWG 2011 and the Natural Resources Act (see
Section I, supra), as well as the ordinances on the gas market rules (adopted by E-Control).
For the construction and operation of energy installations (such as combustion of
coal or gas, waste incineration, hydropower and wind parks) other laws and regulations
must be observed in particular in the field of environment and safety: the Environmental
impact Assessment Act 2000, the Emissions Trading Act 2011, the Water Rights Act 1959,
the Industrial Code, the Emissions protection Act for boilers, the Waste Management
Act and the provisions concerning pressure installations.
2 A summary in English of the Austrian Energy Strategy can be found at www.bmwfj.gv.at/
EnergieUndBergbau/Energiebericht/Documents/Energy%20Strategy%20Austria%20
(engl%20Kurzfassung)%20(2).pdf.
24

ii
Regulated activities
Austria
According to the laws and regulations mentioned under Section II.i, supra, certain
activities are subject to approvals (licences, permits) by different authorities including:
a construction and operation of power plants;
b construction and operation of electricity grids and gas pipelines;
c exploration and production of natural gas; and
d acting as a balance group representative (for the balance group model see Section
IV.i, infra).
According to the ElWOG, the sale of electricity does not require an authorisation.
However, the state-level Electricity Acts provide various regulations which apply to
trading in electricity. For example, the Viennese Electricity Act stipulates that electricity
traders delivering power to final customers are obliged to notify the commencement
of their trading activities to the state government. The commencement of natural gas
trading also has to be notified to the competent authority.
In general, the legal entity or natural person has to enclose certain information to
its application for approval of an activity. The authority has to take a decision and issue
the approval or refuse the application within a certain period of time. The authority is
also entitled to impose specific conditions under which the approved activity can be
carried out.
iii Ownership and market access restrictions
Generally, the Austrian energy law does not distinguish between foreign and domestic
companies. Therefore, no special requirements or limitations are imposed on foreign
companies, neither in the electricity sector nor in the gas sector. The ElWOG sets out a
specific certification procedure for TSOs, however, that are controlled by persons from
third countries. Therefore, it is most likely that the transfer of control over a TSO to
persons from third countries may require prior approval from E-Control. Furthermore, at a
constitutional level, it is set out that at least 51 per cent of the shares of certain listed Austrian
electricity companies, among them Verbund-Gesellschaft, must remain state‐owned.
iv Transfers of control and assignments
Mergers, acquisition of assets or ownership interest of 25 per cent or more, as well as
other forms of change in control in undertakings, are subject to pre-merger notification
to the Federal Competition Authority (‘the BWB’), if the companies involved realised
the following turnover thresholds:
a a combined turnover exceeding €300 million worldwide;
b a combined turnover exceeding €30 million in Austria; or
c at least two of the undertakings concerned each achieved a worldwide turnover
exceeding €5 million.
The notification is initially assessed by the BWB and the federal cartel attorney, who
represents the public interest in competition matters (Phase I). If the planned transaction
gives rise to competition concern the BWB and the federal cartel attorney (the official
parties) may request an in-depth investigation (Phase II) by the Cartel Court. The
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obligation to notify merger activities to the European Commission, if they fall under the
EC Merger Regulation, remains unaffected by the Cartel Act 2005.
Additionally, E-Control, inter alia, has to ensure the regulation of the electricity
sector in Austria; this includes the supervision of competition between the market players
and system operators in the electricity sector, especially regarding the equal treatment
of all market players, which also comprises the monitoring of merger activities in the
electricity sector. There is close cooperation between the BWB and E-Control with
respect to this matter.
In general a Phase I decision must be taken within 25 working days of the day of
notification. If the notification is incomplete the period begins on the day following the
receipt of complete information. Additionally, the Phase I period may be extended to 35
working days under specific circumstance (a request for referral of the case by a MS or
the offer of commitments by the parties concerned).
Where a concentration raises serious doubts about its compatibility with the
common market, the Commission will commence Phase II proceedings. The basic
rule is that a decision must be taken within 90 working days of the date on which
proceedings were initiated. This period may be extended to 105 working days by the
Commission under certain circumstances. An extension of the Phase II time limit may
also be requested by the parties for up to 20 working days. Additionally, the Phase II time
limits can exceptionally be suspended where the Commission has to obtain additional
information owing to circumstances for which one of the undertakings involved is
responsible (‘stop-the-clock mechanism’).
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Electricity
Since the electricity market was liberalised in 2001, the Austrian energy sector has changed
and market economy structures have been implemented. Vertically integrated electricity
undertakings had to unbundle the operation of the grid, which can be considered as
a natural monopoly in terms of legal form and organisation, from the competitionoriented
business areas such as supply or generation. Further substantial changes, in
particular with regard to the organisational structure of energy companies, might result
from the release of the ElWOG, which entered into force in 2011. In compliance with
EU Directive 2009/72/EC the ElWOG regulates that transmission system operators
(‘TSOs’) have to be either ownership unbundled or be set up as an independent system
operator (‘ISO’) or independent transmission operator (‘ITO’).
The ownership unbundling entails a full separation between the operation of gas
and electricity transmission networks from generation and supply activities. The network
operator is required to own and control the network; however, the ownership unbundling
requirements are fulfilled if two or more undertakings that own transmission systems
have created a joint venture acting as a TSO in two or more member states.
With the ISO system the vertically integrated utility (‘VIU’) may retain the
ownership of their network assets, but the network is managed by an ISO that has to be
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fully separated from the VIU. The ISO may not hold any interest in a supply or generation
undertaking. Furthermore, the ISO must execute the network development plan, which
has to be submitted to E-Control. Apart from that, the ISO model regulates that the
network owning company has to disclose all agreements and contracts concluded with
the ISO to E-Control. The ITO model preserves integrated supply and transmission
companies, but obliges the companies to comply with additional rules to ensure that the
two activities are operated independently (e.g., separation of managing functions, coolingoff
periods, establishment of a specific supervisory body, review of network development
and investment decisions). Within the ITO model the TSO must own and operate the
network. E-Control has extensive supervisory rights with regard to the ITO and VIU. In
March 2012 the Verbund Austrian Power Grid, operating the Austrian transmission grid
in large part and being the only control area manager, was granted its certificate as ITO by
E-Control.
The new unbundling requirements had to be fulfilled by 3 March 2012. In the
case of non-compliance with the unbundling requirements, network operators can be
fined by the administrative penal authority.
Gas
The GWG 2011 established with a view to the transposition of EU Directive on the internal
market with natural gas a newly designed unbundling regime for the operation of natural
gas pipelines. In general, by March 2012 the TSO has to comply with one of the following
models provided for by that Directive: OU, ISO or ITO (ITO+). There are less stringent
unbundling obligations for DSO and storage operators. They must only be independent in
terms of legal form, organisation and power of decision (legal and functional unbundling).
ii Transmission/transportation and distribution access
With a view to the electricity sector, DSOs have the obligation to publish general terms
and conditions and to conclude, under these terms and conditions, agreements with end
users and producers, providing for their connection to the grid (in line with the general
obligation to connect); in line with this obligation regarding the DSO, grid users have
the right and also the obligation to connect their facility to the DSO operating on their
respective service territory. The general terms and conditions for net access must not
be discriminatory, include abusive practices or unjustified restrictions, or endanger the
security of supply or quality of service. They must also be adapted within a control area
between the grid operators.
The respective Electricity Acts of the federal states lay down conditions under
which a DSO may refuse a grid connection. These exceptions to the general obligation
specifically include cases where the connection to the grid would not be economical in
relation to the interests of all system users. Furthermore, grid access may be denied if the
grid user requires or wants to feed in electricity at a voltage higher than 110kV. In this
case it is the TSO who has the obligation to grant access to the transmission grid.
The electricity laws of the federal states provide for area monopolies for electricity
distribution grids. Therefore, a concession for such type of grid is only granted as long as
no other distribution grid exists. The implementing laws of the states have to foresee that
the distribution grid operator has the exclusive right to connect all end users and producers
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in the area for which it was granted its concession. Only certain direct lines and older
connections as well as withdrawing parties with a voltage higher 100kV are exempted.
The existing Austrian gas transit pipelines are owned and operated by OMV Gas
GmbH. Domestic transmission and distribution networks are owned and operated by
various TSOs and DSOs. Domestic transmission and distribution networks are subject to
regulated third-party access, which means that GTCs (see Section IV.ii, infra) are approved
ex ante and charges are regulated. The DSO operating the system to which the customer
wishes to be connected is obliged to grant non-discriminating access under approved GTC
and regulated tariffs. DSOs are obliged to enter into private law contracts with consumers
on the connection to the natural gas distribution system and system utilisation under
approved GTC within their distribution area. In certain cases the grid operator may refuse
the connection of a grid user. Such a decision is subject to review by the regulatory authority.
There is no exclusive right in the natural gas sector as for the operation of electricity
distribution grids.
iii Rates
Users of electricity and natural gas grids have to pay a ‘system utilisation charge’. It is
made up by various charges, for example, for grid losses (in the case of electricity), grid
admission charge, grid provision charge or for metering services.
The charge is determined by E-Control by way of legal ordinance. The ordinance is
based on the network costs and quantity structure of the network operators, both of which
are determined through an administrative decision of E-Control. Network operators have
the right to appeal against this decision. The terms for the provision of transmission services
are permitted by E-Control through individual administrative decisions.
iv Security and technology restrictions
In 2008 the Austrian government adopted the Austrian Program for Critical
Infrastructure Protection (‘the APCIP’) incorporating energy infrastructure. As regards
specific measures the programme aims – beyond already existing legal obligations – at a
‘cooperative approach’ between the authorities and the operators of critical infrastructure.
To this end, and taking into account economic feasibility and usefulness, the respective
protection level shall be defined and subsequently implemented in close cooperation.
As an EU Member State, Austria must implement EU Directive 2008/114/EC on
critical infrastructure, which can be done through the APCIP.
With regard to tackling cyber security there are general obligations to provide
for data security laid down in the Data Protection Act. Such requirements may also
stem from agreements based on civil law. The Austrian government, however, recently
announced that until the end of 2012 a national cyber-crime strategy should be adopted
and implemented.
IV
ENERGY MARKETS
i Development of energy markets
As previously outlined, the Austrian markets for electricity and natural gas were liberalised
in 2001. Consumers may choose their energy supplier freely and guarantee that all trade
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and supply deals can be settled correctly. Therefore, Austria decided to implement the
‘balance group model’ as it was previously used in the Scandinavian states. The balance
group is a virtual group of suppliers and customers within which electric energy procured
and supplied is balanced. Electricity suppliers or traders may decide whether to join an
existing balance group or to start with their own. The whole system is described in detail
in the market rules for the electricity sector (see Section IV.ii, infra).
The natural gas market also uses the aforementioned balance group model.
ii Energy market rules and regulation
In the electricity market three groups of market rules exist:
a GTCs;
b the Electricity Market Code;
c technical and organisational rules (‘TORs’) for system operators and users.
These rules are drawn up and published by the regulatory authority E-Control in
consultation with the relevant market players. They cover, in particular, the following issues:
a the allocation of responsibilities to given market players and system operators;
b the general terms and conditions of distribution and transmission system
operators, balancing group representatives, green electricity balancing group
representatives, and clearing and settlement agents;
c standardisation of the liability rules;
d supplier switching procedures;
e TORs;
f standards for hardware, software and data management (who gets what data and
when);
The market rules in the gas market are established similarly to the electricity market rules
and address, inter alia, the following issues:
a the allocation of responsibilities to given market players and system operators;
b GTCs for individual market participants;
c TORs; and
d the interactions of market players, and schedules and data formats (other market
rules).
Agreements between the different participants on the electricity and natural gas markets
must be based on these market rules. Regarding the market model regarding gas trading
see Section IV.iv, infra).
iii Contracts for sale of energy
Individual contracts for the sale of electricity and natural gas are permitted in Austria. In
contrast with the charges for grid use, energy tariffs are not regulated.
However, in addition to the obligation to comply with the market rules presented
in Section IV.ii, supra, the Electricity Acts of the federal states provide for specific rights
for electricity end customers. Suppliers are obliged to inform the customer before the
closing of an agreement about the essential contents and to distribute an information
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sheet, for which there are specific minimum requirements concerning the design and
content. The GTCs must comply with the provisions of the Consumer Protection Act
and be notified to E-Control.
Purchase agreements concerning electricity from non-EU Member States are
prohibited if such states fulfil their electricity demands from installations that do not
comply with the best available techniques or that threaten people, animals and plants.
The same applies to installations not properly treating their waste and that do not have a
waste management methodology.
iv Market developments
Power and gas utilities are currently still adapting their company structures to the
strengthened unbundling requirements as promoted by EU energy law.
In order to comply with the EU Gas Directive, Austria had to reorganise its gas
market model. In future the Austrian Gas market will only have three market areas where
the transit and national distribution systems will be merged. The existing pipe-in-pipe
system will be abolished. TSOs will be required to appoint a market area manager that
will ensure coordinated operation of the network in the market area. The responsibilities
of the market area manager will include running the VTP, managing balancing groups,
congestion management and controlling distribution of physical balancing energy.
In accordance with this new market model, the physical hub will be transformed
into a VTP with one entry or exit zone (‘entry or exit-model’). A VTP is a notional point
at which gas can be traded within the market area after its entry and before its exit. The
VTP is not a physical entry or exit point but enables grid users to transfer energy from one
balancing group to another within the market area. According to the new model, traders
and grid users will be able to sell and buy at the VTP without holding capacity rights.
An important market development is still the increased use of renewable energy
sources (mainly hydro, wind, biomass and photovoltaic). In order to provide for control
energy with short activation times further storage and combined cycle gas turbines will
be available on the market in Austria.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
The long-term development of Austrian energy production and structure has resulted in an
increase of renewable energy: 60 per cent of gross domestic electricity consumption now
comes from renewable energy sources (‘RES’). Hydropower, which constitutes more than
60 per cent of RES used for electricity generation, is the most important domestic source of
renewable energy; however, the EU Renewable Energy Directive requires Austria to attain a
national target of 34 per cent share of all national energy sources from RES.
As the current share of RES in Austria ranges below 30 per cent (23.4 per cent
in 2005 and approximately 30 per cent in 2010), Austrian energy policy has made
essential efforts to expand RES. To ensure that the national overall target of 34 per cent is
achieved, the Federal Minister of Economy, Family and Youth and the Federal Minister of
Environment released political guidelines titled ‘Austrian Energy Strategy’, published in
March 2010 (see also Section I, supra). The AES lays down the basic principles of energy
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Austria
policy for the next 10 years and calls for a rapid but sustainable expansion of energy
generation from renewable resources. Based on that strategy, the national renewable
energy action plan (‘the NREAP’) was drawn up, which, under the Renewable Energy
Directive, had to be notified to the European Commission by June 2010. The NREAP
aims at the increase in energy generation from hydropower, wind power, biomass and
solar sources. Moreover, the NREAP states that wind power, biomass and solar sources
will benefit from the green electricity promotion scheme.
Legal provisions concerning renewable energy can be found in the ElWOG
and the Green Electricity Act. In compliance with the New EU Electricity Directive,
the ElWOG stipulates that, in case of grid capacity shortfalls linked to the necessity of
dispatching generation installations, the TSOs have to give priority to installations using
renewable energy resources.
In July 2011 a new Green Electricity Act (‘GEA’) was adopted in order to
implement the targets of the AES and the NREAP. Contrary to several other EU Member
States Austria strengthened the support scheme by the new GEA 2011. It introduces,
among other issues, a strong increase of the feed-in tariff for energy generated by wind
parks located in Austria (for further details on the extended support scheme see Section
VI, infra). The new Cogeneration Act contains provisions on the promotion of combined
heat and power plants. This promotion regime was formerly part of the GEA. However,
according to the ElWOG and the GEA, there are no obligations or commercial incentives
for TSOs to invest in additional capacity to service renewable energy plants.
ii Energy efficiency and conservation
A strong increase in energy efficiency is a key part of the AES. To this end the AES
defines measures in the following action fields: reduction of the heat and cooling
demand in buildings, reduction of electricity consumption in private households and
commercial facilities, better use of industrial waste heat and a more efficient mobility.
In 2020 the final energy consumption in Austria should be 1100PJ, which corresponds
to consumption in the year 2005. A draft Federal Energy Efficiency Act will shortly be
presented for public consultation, which could contain several measures to raise energy
efficiency, in particular in commercial facilities.
Also, the federal states have set up energy-efficiency programmes mainly consisting
of targeted funding and monetary support schemes; there are also binding requirements,
such as a mandatory energy audits for certain commercial activities.
iii Technological developments
Clean energy technology accounts for around 50 per cent of the additional turnover
generated by the Austrian environmental technology industry since 2003. The most
important technologies are cogeneration installations, revamping of existing installations,
biomass and hydropower. 3
3 See Austrian Institute for Econonomic Research, Austrian Environmental Technology
Industry (2009), www.energieklima.at/fileadmin/user_upload/pdf/Zahlen_Daten/0908_
Umwelttechnikstudie.pdf.
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The AES acknowledges that the national energy policy should also contribute to
the aims of further growth and the creation of new jobs. In Austria several instruments
exist in order to support technological developments in the field of energy. Among these
are the GEA or the Energy and Climate Fund established at federal level. Every year
innovations are awarded the ‘state prize on environment and energy technologies’.
Since about 2005 the process of adapting the Austrian electricity grid system
to ‘smart’ technologies with a view to the better integration of RES and optimal use
of smartmetering is ongoing. Regarding smartgrids, the AES states that from 2014 on
new incentives for innovation and a cost acknowledgement should be laid down. These
measures should foster research and development activities for a new grid infrastructure.
VI
THE YEAR IN REVIEW
Several landmark decisions were taken in 2011 in the Austrian energy policy. Among
those were the new GEA with a strong expansion of the support, the new Gas Act or the
Act Prohibiting the Geological Storage of Carbon Dioxide.
i New Green Electricity Act
In July 2011, the Austrian parliament passed the amendments to the GEA 2012, which
will bring about a substantial boost of RES projects in Austria. The new Act transposes
RES Directive 2009/28/EC and aims at reaching the EU 20-20-20 goals. Since 2007, the
development of new RES projects has stagnated because the available annual support funds
have already been exhausted. Due to the fact that the supports are granted on a first-come,
first-served basis, a large number of eligible RES projects had to be put on hold. In order to
speed up development, the GEA provides that the support for those delayed projects will
be granted immediately. All other provisions of the GEA will only become effective after
the EU has provided its consent. The GEA stipulates that the green electricity supported in
line with the Act and injected into the public grid should reach 15 per cent of total supply
to consumers in 2015. This corresponds to an additional 700MW of hydropower, 700MW
of wind power, 100MW of biomass and biogas, as well as 500MW of photovoltaics, which
will have to be installed by 2015. In order to reach this goal, the support funds have had to
be substantially raised. From the current €21 million, the annual funds will be raised to €50
million, of which €8 million will be assigned to photovoltaics, €10 million to biomass and
biogas, €11.5 million to wind power and €1.5 million to small hydropower. The remaining
€19 million will be reserved for hydro and wind power projects, as well as photovoltaics
with a capacity of more than 5kW peak once their budgets are exhausted.
ii Criteria catalogue on hydropower
Implementing the Austrian Energy Strategy the Minister of Environment adopted in January
2012 the ‘criteria catalogue for hydropower’. This provides general rules and criteria on the
identification of Austrian waters eligible for hydropower with regard to environmental
protection and in particular the EU Water Framework Directive. The catalogue will act as
a guideline document for authorities and operators or potential operators of hydropower
plants and simplify the project preparation and the licensing procedure.
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iii
New Emissions Trading Act
Austria
The new Emissions Trading Act transposes the new emissions-trading scheme as provided
in Directive 2009/29/EC (amending ETS Directive 2003/87/EC). From 2013, power
generators will have to buy emission allowances for the operation of their power plants
(the power sector no longer benefits from free allowances).
iv (Temporary) ban of carbon dioxide storage
Geological storage of carbon dioxide and also the exploration of cavities are legally banned
by the Act Prohiting the Geological Storage of Carbon Dioxide. Only certain research
activities are exempted from the ban. Until the end of 2018 the federal government has
to present a report whether the ban should be kept or abolished.
VII
CONCLUSIONS and OUTLOOK
With the finalisation of the energy strategy in 2009 Austria has a comprehensive strategic
concept for its national energy policy and a clear position towards the energy policy of
the EU. The renewal and the extension of transmission and distribution grids is still
a major challenge, however. The activities in this field have to be accelerated in the
electricity sector, particularly with a view to raising an amount of RES to be integrated.
Further, so-called independent grid systems (‘island solutions’) are becoming
more and more attractive. The increase of energy efficiency in all relevant sectors will
also, however, be challenging, as the current federal and state policies and programmes
are not coordinated enough. For example, as federal support for improving the selfsufficiency
of buildings was greatly extended, several states reduced their own support
schemes signalling the need to adopt austerity measures.
With a view to increasing the diversification of supply sources for gas, new gas
pipelines such as the Nabucco project are necessary.
After 10 years of liberalisation in the electricity and gas sector, the number of
consumers changing their energy supplier is still rather low. Several instruments were
implemented to support customers in comparing the energy tariffs of different suppliers
and to assist them switching supplier; 4 however, additional regulatory measures might be
discussed in the future.
4 See the online tariff calculator and switching assistant provided by E-Control: www.e-control.
at/en/consumers/electricity/supplier-switching.
33

Chapter 3
Brazil
Guilherme Guerra D’Arriaga Schmidt 1
I
OVERVIEW
Over the past 15 years the Brazilian electric power sector (‘the BPS’) has undergone
continuous reform in its framework in order to enable new investments to supply the
increase of the power demand derived from national economic growth.
In 1995, Law 9,074 was enacted bringing competition to the power
commercialisation and generation sectors. Further, distribution companies were privatised.
The independent Electric Power National Agency (‘ANEEL’) was created by Law
9,427 in 1996 to oversee the electric power market. A wholesale power market was
incorporated in 1998 and power trading companies emerged.
Although the Brazilian Ministry of Mining and Energy (‘the MME’) has developed
other forms of power generation, the BPS is still mainly composed of hydroelectric power
plants, encompassing approximately 80 per cent of its power capacity. In view of its large
territory and of the long distance from the big hydroelectric power plants to the largest
cities (centres of high power consumption), the BPS is based on a very long and complex
transmission system. Consequently, strong climate changes and severe dry seasons may
affect Brazilian power capacity and the price of energy.
The BPS is basically composed of two markets. First, a regulated power market
is mainly composed by the distribution companies and the captive consumers. Their
commercial relation is fully regulated by ANEEL. The distribution companies are
entitled to charge and receive a determined rate (tariff) for the power then supplied. They
are, however, obliged to acquire their whole power demand through the power auctions
organised and supervised by ANEEL.
1 Guilherme Guerra D’Arriaga Schmidt is a partner at L O Baptista Schmidt Valois Miranda
Ferreira Agel.
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Brazil
Alternatively, there is the free power market. Free power consumers, power
generators and trading companies are the main agents in this market. These agents are
free to negotiate their own power volumes and prices.
The Brazilian government also actively participates in the regulation of the BPS
in order to ensure the energy supply, protect the level of the power rate and plan the
expansion of the energy network to distant areas of the country.
II
REGULATION
The Brazilian government has paid close attention to the regulation of the BPS in order
to secure investment for a strong and diversified energy matrix to cover the growing
power demand throughout the years.
Due to its strategic importance, there are extensive regulations for all segments,
in order to achieve legal security and the technical parameters needed for its expansion.
i The regulators
The BPS is basically structured by a group of federal laws and several administrative
rules. It falls under the responsibility of the MME, which in turn answers to the Brazilian
president. The MME formulates and implements the policies in the electric sector in
accordance with the guidelines provided for by the National Energy Policy Council (‘the
CNPE’).
The MME is responsible for certain activities related to exploitation and
exploration of natural resources such as geology, mineral and energy recourses, mining,
metallurgy, oil, fuel and electric power, including nuclear energy.
Currently, the MME is the authority responsible for granting concessions and
permissions to agents in the electric sector for exploiting electric power services and
facilities. Such responsibility was previously carried out by ANEEL.
The oil and natural gas sector and the electric power sector are regulated by
different regulatory agencies. ANEEL regulates the electric sector and the National Oil
Agency (‘ANP’) is responsible for the regulation of the oil and natural gas activities. Both
ANEEL and ANP are linked to the MME.
ANEEL is a special independent regime, created by Law No. 9,427/1996 for
the purpose of regulating the electric sector. Although ANEEL is linked to the MME,
it has technical and political autonomy to regulate, supervise and monitor the activities
of generation, transmission, distribution and commercialisation of electric power, in
compliance with the guidelines established by the federal government.
ANEEL has two hierarchical levels. The board of directors is composed of five
directors, one of whom is the director general; the directors make collective decisions.
The board approves resolutions and is the final instance in administrative proceedings
conducted before ANEEL. At the level below the board, there are 20 specialised
superintendents, each with particular expertise. The superintendents are assistant to the
board.
With respect to its regulatory function, the acts performed by ANEEL are
externalised by way of normative resolutions (creating technical rules), authoritative
resolutions (prior authorisation to allow certain acts conducted by an agent), approving
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Brazil
resolutions (approving act previously performed by an agent) and joint resolutions
(creating rules jointly with other regulatory agencies).
With regards to its supervisory functions, ANEEL is responsible for the
inspection and supervision of the activities carried out by the agents in the electric sector.
Administrative proceedings for this regulatory agency follow Law No. 9,784/1999, 2
ANEEL Normative Resolution No. 273/2007 3 and ANEEL Normative Resolution No.
63/2003. 4
This function of ANEEL also encompasses the revision and eventually the
imposition of fines against holders of concessions or permissions, or authorised agents
that violate the governing rules of the BPS.
ANEEL’s main responsibilities and obligations under the law are:
a the management of concession or permission contracts of electric power public
services, as well as the supervision, directly or through state agencies, of the
concessions, permissions and authorisations of electric power services;
b the authority to decide, at the administrative level, the differences between
concessionaires, permissionaires, authorised or independent power producers
(‘IPPs’) and self-producers, as well as between these agents and their customers;
c the establishment of restrictions, limitations and conditions on companies
and corporate groups willing to either assign or transfer their concessions,
authorisations or permissions in order to protect effective competition among
the agents, preventing economic concentration in the electric power services and
activities;
d the imposition of administrative fines on agents for non-compliance with their
regulatory obligations; 5
e the calculation of rates for the provision of electric power supplies carried out by
distribution concessionaires, and establishing goals to be fulfilled by distributors
to universalise the use of electricity;
f the approval of the rules and procedures for the commercialisation of electric
power; and
g the organisations and promotion of auctions to accommodate market needs.
Although ANEEL has the exclusive authority to supervise the BPS, other institutions
have important functions for its operation. The main institutions are listed below:
a The CNPE it is a governmental body linked to the Brazilian president, created by
Law No. 9,478/1997 and regulated by Decree No. 3,520/2000. Its main function
is to suggest policies and guidelines to promote the sensible use of national energy
resources in order to maintain the lowest possible rates for consumers.
2 The Federal Administrative Proceedings Law.
3 ANEEL Organisation Standards.
4 Disciplinary Administrative Proceedings.
5 For each infraction, the fine is limited up to 2 per cent of the annual earning, or of the estimated
value of the energy produced in case of self-production and/or independent power production,
corresponding to the 12 months prior to the issuance of the violation notice.
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Brazil
b
c
d
e
The Monitoring Committee of the Electric Sector (‘the CMSE’) was approved
by Law No. 10,848/2004 and created by Decree No. 5,175/2004. Its main
responsibility is to monitor the continuity and security of the electricity, natural
gas, oil and oil derivatives supply throughout the country. The CMSE also
indentifies any risks to the energy supply and develops proposals for adjustments,
solutions and recommendations to predict or resolve risk situations.
The National Electric Power System Operator (‘the ONS’) is a non-profit private
entity created by Law No. 9,648/1998 and is the manager of the national
interconnected transmission system (‘the SIN’). The ONS is formed by all the
agents connected to the basic grid. 6 The principal functions of the ONS are:
• planning and programming the operation and centralised dispatch of
power generation, envisaging the optimal operation of the SIN;
• the supervision and coordination of the operation centres of the electrical
systems;
• the preparation and presentation to the MME of studies relating to the
expansion and reinforcement of transmission systems; and
• the preparation and presentation of new rules for the operation of the basic
grid for the approval of ANEEL.
The Energy Research Company (‘the EPE’) is a public company that conducts
studies and research to provide technical support for presenting long-term power
planning in Brazil. The EPE also identifies and determines potential energy
resources that should be developed in Brazil. Further, the EPE has an important
role in the preparation of power auctions conducted by ANEEL for the sale of
energy to distribution companies, technically qualifying the projects that may
participate in auctions.
The Electric Power Commercialisation Chamber (‘the CCEE’) is a non-profit
private entity regulated and supervised by ANEEL. The CCEE was created by
the agents of the Brazilian electric power market, as provided for in Law No.
10,848/2004. It is responsible for registering and processing the volume of all the
contracted energy in the power market. Short-term power transactions are also
financially settled at the CCEE. Long-term power agreements are also registered
with the CCEE but are financially settled directly by the parties. The CCEE is
also responsible for the calculation of the clearance price of the difference in
the contracted volumes in the short-term market, as well as being responsible
for conducting auctions for the sale of energy to distribution companies in the
regulated market.
ii Regulated activities
All activities in the BPS require corresponding authorisations from the granting
authorities. The operation of electric power services and facilities usually occurs by way
6 The basic grid contains substations and transmission lines at a voltage equal to or higher than
230kV, which connect the four regions of the country, except for the isolated system, located in
the northern region of Brazil.
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Brazil
of concession or authorisation. The electric power distribution and transmission activities
shall be subject of concession. Power generation companies, which can be classified as an
IPP or as self-producers, are subject to either concession or authorisation. This depends
on the capacity and type of energy produced. Power trading companies are subject to
authorisation.
In accordance with Article 175 of the Constitution, 7 public service concessions
are generally awarding following a bidding procedure. In the case of electric power public
services, the bidding procedure is conducted through an auction method. Agents wishing
to participate in such auctions must submit several documents to the EPE, which will
then analyse and assess the agents’ technical qualifications to take part in the auction.
With respect to hydroelectric plants, projects are initiated by the government,
which will obtain the prior environmental licence. The construction and exploration of
the plant is then subject to an auction.
Under the new model, the auctions intend to regulate the rate (i.e., the lowest
price possible at which the generator can sell the MWh). The generator that wins the
auction will sign a concession contract establishing the maximum amount that the
generator can provide to the basic grid. This guarantee is calculated by the MME for
each power plan and it represents the maximum amount of energy that power plant may
contract. Should the power plant generate more than the guarantee specifies, the excess
is sold on the short-term market; however, should the power plant generate less than the
guarantee, the generator agent must buy the difference on the short-term market in order
to supply the whole contracted energy.
The granting of a transmission concession is also subject to an auction in order
to hire the most competitive agent with the lowest rates. The auction is preceded by
studies of the ONS and of the EPE that must confirm the necessity to construct new
transmission lines for the expansion or reliability of the SIN. The agent that bids the
lowest price to provide the transmission services is the winner.
In connection with the distribution companies, new concessions were granted
to the companies when they were privatised in the 1990s through auction procedures.
The authorisation to perform as a self-producer or IPP is regulated by ANEEL
Normative Resolutions Nos. 389/2009 and 390/2009. In accordance with ANEEL
Normative Resolution No. 390/2009, the company’s legal representative must provide
ANEEL with the documents confirming its technical and legal qualifications and the
tax position of the company, jointly with the licences listed in the first annex of the
resolution.
In relation to power trading activity, ANEEL Resolution No. 265/1998 determines
the necessity to constitute a legal entity for the purpose of commercialising energy. The
authorisation is only granted upon presentation of documents before ANEEL that
confirms the fiscal and legal qualifications of the agent, and its satisfactory economic and
financial position.
7 ‘It is incumbent upon the State, as provided by law, directly or under concession or permission,
always through a bidding process, the provision of public services.’
38

iii
Brazil
Ownership and market access restrictions
As a general rule, the companies that operate in the BPS should be located within Brazilian
territory. With respect to the foreign investment made in the BPS, Brazilian legislation
does not restrict the participation of foreign companies in operational companies.
However, with the new regulatory model currently in force, there are strong rules
to separate the activities carried out by the agents from the BPS. Such restrictions preserve
the competitiveness of the power market and also the lowest power rates for the sector.
In this sense, power distribution concessionaires cannot develop any activity related to
power generation, transmission of energy or trading of energy; they can only acquire
energy through an auction procedure based on the lowest price and can only sell energy
to captive power consumers, in accordance with the power rate determined by ANEEL.
On the other hand, power generation companies cannot be either associated
with 8 or controlled by power distribution companies.
iv Transfers of control and assignments
The concession, permission or authorisation of electric power services granted to an
agent is personal. Therefore, any change of control is subject to the prior approval of the
granting authority.
In this sense, Law No. 8,987/1995, 9 which provides the general rules for the
concessions and permissions in the public services, requires the prior consent of the
granting authority in case of a direct or indirect change in the concessionaire’s corporate
control. If this procedure is not complied with, the concessionaire may be subject to
penalties or may even lose the concession. ANEEL’s board of directors has the delegated
powers to review and grant such consent after the study of its Office of Economic and
Financial Supervision.
Participants of the BPS have called for clearer rules, particularly with respect to
trading agents; a new normative resolution relating to the rules applicable to obtaining
prior consent for the transfer of corporate control of agents has recently been subject to
a public hearing. 10
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
In the BPS, the services of energy transmission and distribution are considered natural
monopolies, since competition in these segments does not result in any lowering of
electricity rates.
For that reason, transmission and distribution services providers are entitled
to exclusively operate in their respective areas of concession, as provided for in their
concession contracts.
8 A company in which the investor holds material influence (Article 243 of Law 6,404/1976).
9 ‘The concession or corporate control transfer of the concessionaire without prior consent of the
granting authority results in forfeiture of the concession.’
10 ANEEL Public Hearing No. 65/2011.
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Brazil
The Brazilian rules divide the country into four sub-regions, interconnected by
the SIN; there is also an isolated region in the north of Brazil. Although there are certain
small restrictions and small differentials in price among the sub-regions, the transmission
lines allow power transactions from the four different sub‐regions that are part of the
SIN.
i Vertical integration and unbundling
Until the 1990s, the BPS was vertically integrated, mainly in view of the fact that there
was no competition or significant private participation. In 1995, however, Law 9,074
started certain important changes to the BPS. The first measures were implemented to
bring competition into the power generation and power trading sectors. Also, the BPS
initiated the privatisation of the state electric power distributors. 11 In other words, the
BPS underwent modification because of the government’s recognition of the necessity to
attract new players in order to attract the required investment in the sector. Consequently,
the state companies that operated in all segments were disaggregated and the majority
of the Brazilian power distributors were privatised. Nevertheless, the legal obligation to
the end of the companies’ vertical integration was only introduced in 2004, by Law No.
10,848/2004, mainly motivated by competitive issues.
Pursuant to the new wording of Article 4, Paragraph 5 of Law No. 9,074/1995,
electric power distribution companies cannot carry out any activity related to electric
power generation and or transmission services. They are only allowed to sell energy to
captive power consumers 12 in accordance with the rate approved by ANEEL.
Moreover, power generation companies cannot be related to power distribution
companies, as explained in Section II.iii, supra.
ii Transmission/transportation and distribution access
In accordance with Law No. 9,074/1995, any electric power agent has the right to
access either the distribution or the transmission systems, upon reimbursement of the
transportation costs; such costs are calculated in compliance with a criteria set out by
the granting authority. ANEEL Resolution No. 281/1999 and ANEEL Normative
Resolution No. 67/2005 regulate the access to the basic grid (transmission) and the
distribution systems.
The agent interested in connecting to the transmission or to the distribution
system must request the access either to the ONS or to the distribution or transmission
concessionaire responsible for the access point where the connection should be made, as
the case may be. 13
The ONS must prepare a technical study of the feasibility of access to the
basic grid. This technical study will determine the best alternative for the envisaged
11 A few generators were privatised, but privatisation occurred mainly in the distribution segment.
12 Captive power consumers are the consumers, with charge lower than 1,500kW, that are obliged
to buy electric power from local distributors.
13 ANEEL Resolution No. 281/1999, Article 7, I and II.
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Brazil
connection, considering the technical alternatives and the lowest costs involved in the
implementation of the access.
With respect to the access to a distribution system, a technical study of the
feasibility of access must be performed by the local distributor, which will determine the
best point of connection.
Prior to the implementation of the access to the transmission system, the user must
enter into the transmission system use agreement (‘CUST’) with the ONS, establishing
the technical conditions relating to the use of the transmission lines. The ONS signs the
CUST on behalf of all the transmission companies, representing such concessionaires
with the user. The user must also sign and the transmission connection agreement
(‘CCT’) with the local transmission concessionaire responsible for the point of access,
establishing the responsibilities for the implementation, operation and maintenance of
the point of connection and its corresponding charges. The ONS signs the CCT as an
intervening party.
With respect to the connection to the distribution system, the user shall enter
into the distribution system use agreement and the distribution connection agreement
with the local distributor concessionaire. These agreements have similar characteristics to
the CUST and the CCT.
iii Rates
Transmission and distribution concessionaires are entitled to be compensated for the
connection services to either the transmission or distribution system and for the use of
the transmission and distribution lines.
The costs for the use of the transmission or distribution systems are owed by all
users in connection with either the contracted or verified volume of energy and the rate
due by the use of the transmission or distribution systems. With respect to consumers,
the calculation of the costs for the use of the transmission or distribution systems are
based on such rates due during both peak and off-peak hours and the volume of energy
consumed during these hours.
The rate for the use of transmission system is calculated by ANEEL and annually
adjusted taking into consideration the concessionaire’s permitted annual revenue. In the
same way, the rate for the use of distribution system is calculated by ANEEL with respect
to each distributor, and revised every three years. The calculation takes into account the
investments made by the distributor with the distribution lines and the costs incurred by
the distribution activity.
IV
ENERGY MARKETS
i Development of energy markets
In 2000, Brazil suffered with a severe power supply crisis, mainly caused by a halt in
contracted investment in the electric power generation together with a severe dry season
that adversely affected the hydroelectric basins. This crisis demonstrated weaknesses in
the electric power sector and led to changes, mainly introduced by Law No. 10,848/2004.
The current energy market’s structure seeks to ensure expansion, securing the
sale of energy derived from new power plants and, consequently, a return of the capital
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Brazil
invested in the sector, together with the promotion of rate regulation and the continuity
of power supply growth. On such basis, Law No. 10,848/2004 confirmed and developed
both the free power market and the regulated power market.
Under the regulated power market, distribution concessionaires should have their
projected power demand fully contracted, by means of auctions based on the lowest
price. The price for the acquisition of the energy resulting from the auctions is reflected
in the adjustment of the rate approved by ANEEL.
The EPE, based on its studies, establishes a maximum price for the sale of
the electric power by the generators, who then offer to sell energy at the lowest price
considered viable by them. Such procedure protects rate regulation, reducing the final
rate for the captive consumers.
On the other hand, under the free power market free power consumers and
power-trading companies should have all of their demand contracted through power
and sale agreements registered with the CCEE. They may buy energy from any power
generator or other power trading company.
In both power markets there is the obligation for the energy user to contract its
full demand. This rule promotes transactions in the sector and reduces the risks related
to changes in the power price. This structure brings certain comfort to the agents in the
sector since it promotes the signing of power agreements, securing the receivables for
new investments. On the other hand, the government has the ability to decide what type
of energy it intends to promote through the studies prepared by EPE for the auctions,
also protecting the possible lowest price.
ii Energy market rules and regulation
Following the trend in other countries, the BPS protects the natural monopolies
granted to the concessionaires of distribution and transmission services and promotes
competition among the power generators and trading companies.
The Electric Power Commercialisation Convention and the CCEE
Commercialisation Rules and Procedures regulate the sale of electric power. Basically,
all power transactions should be made through power agreements, whose volumes are
registered with CCEE. The CCEE Commercialisation Rules and Procedures establish
the general terms and conditions related to the accounting rules, contract and physical
guarantees, penalties, liquidation and contracting of power reserve and procedures to
make the registration of the contracts. It also establishes the settlement price for the
energy and the forms of disclosure of the results.
iii Contracts for sale of energy
In the BPS, there are two types of contract: the purchase and sale agreement in the
regulated power market (‘regulated contract’) and the power purchase agreement in the
free power market (‘free power purchase agreement’).
The parties, observing the necessity to register its contracted volume with the
CCEE, may negotiate the terms and conditions of a free power purchase agreement;
however, the parties do not negotiate the terms and conditions of the regulated contract.
When the MME determines an auction is going to take place, a public hearing is held
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Brazil
and a draft of the concession contract is issued. Therefore, the agents have knowledge of
the terms and conditions of the regulated contract before they take part into the auction.
It is prudent that the conditions of the regulated contract are determined by
the granting authority in order to ensure the envisaged provision of the electric power
services.
iv Market developments
There appears to be a continuous trend of the Brazilian government in promoting the
development of different types of clean energy. The wind power market has received
special attention from the EPE and, after an auction procedure held in 2011, many wind
power projects were contracted at competitive prices.
The solar energy market is currently a focus, due to the fact that it is a renewable
and non-polluting source and solar resources are particularly plentiful in Brazil. As a
result, ANEEL is discussing the possibility of a discount for solar generators equivalent to
80 per cent of the rates for the use of transmission system and for the use of distribution
system for the first 10 years of the plants’ operations. After such term the discount would
be reduced to 50 per cent.
The state governments are also engaged in the development of the solar energy
industry in order to bring it in the electric power matrix; however, this source is still
considered expensive, inefficient and not currently necessary.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
In Brazil, wind and biomass sources are complementary to hydro sources, especially
considering that the dry season corresponds with the biomass harvest and the windy
season. For this reason, these renewable sources, which jointly with small hydro plants
(‘PCHs’) are called alternative sources, are part of a development programme.
The Program to Foster Electric Power Alternative Sources (‘PROINFA’), as
provided by Decree No. 5,025/2004, was created to increase the participation of the
wind, biomass and PCH sources in the SIN and diversify existing and overexploited
energy matrices.
The main strategic objectives of PROINFA are the diversification of the Brazilian
energy matrix, increasing the power supply security in a sustainable manner; the
reduction of emissions of greenhouse gases; and the encouragement of new technologies.
The contract resulting from the auction held for one of the alternatives sources of
PROINFA has special conditions, such as a discount of 50 per cent or 100 per cent of
the rate for the use of transmission system or the rate for the use of distribution system,
as provided by ANEEL Normative Resolution No. 77/2004.
ii Energy efficiency and conservation
Energy efficiency in Brazil involves the rational use of the energy sources in accordance
with their cost of production and availability; the ONS is responsible for national
energy efficiency. It controls the SIN, deciding which power unit will be dispatched, in
accordance with its efficiency in certain seasons.
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Brazil
In view of the specifics of the Brazilian electric power system the ONS takes into
account the most appropriate power generators to be dispatched in view of eventual
transmission restrictions or low volume of the reservoirs of hydroelectric plants. The cost
of the dispatch of a different power plant is borne by all the agents as a charge of the
electric system.
Moreover, certain power generators are constantly adopting new technology to
improve their efficiency, which increases their physical guarantee and consequently may
allow for the sale of a greater volume of energy.
iii Technological developments
Besides the progress of the solar energy technology, and the competitiveness of wind power
projects in Brazil, the use of methane thermal power plants are also being studied,which
results from the landfill and swine dejects, without economic destination. As a result,
these projects may be part of an environmental solution against the methane pollution.
VI
THE YEAR IN REVIEW
ANEEL has already confirmed that will perform at least two energy auctions in 2012.
The first is expected to be held on 28 July. It will grant a three-year period for the
construction of the plant (‘A-3’). For the A-3 auction, there are registered generation
projects dealing with wind, gas thermal, biomass, PCHs and hydroelectric power plants.
The second auction is expected to be held on 16 August, which will grant a fiveyear
period for the construction of the plant (A-5). The term for the registration for this
auction is not yet finished.
It can be seen that ANEEL is maintaining its policy of promoting the expansion
of Brazilian power capacity, an expansion requiring investment from the private sector
in the new generation of power plants and transmission lines and serious long-term
governmental planning.
VII
CONCLUSIONS and OUTLOOK
In view of the current structure of the BPS, the government needs to continue to promote
the expansion of the national power capacity in order to cope with the growing power
demands of Brazilian industry and other power consumers.
In this scenario, new investments will be required in next-generation plants and in
transmission lines, to guarantee competitive power supplies at low costs, and delivering
attractive opportunities for the private sector.
44

Chapter 4
Bulgaria
Yassen Spassov 1
I
OVERVIEW
Over the past decade, a number of reforms have occurred in the continuously maturing
Bulgarian electricity market. Changes to the electricity industry primarily purport to
avail the market of the benefits of competition and protect the interests of customers. The
process of restructuring the electricity market in Bulgaria, however, falls behind the pace
of European liberalisation. Furthermore, the socioeconomic conditions for competition
are not yet observed in practice. The electricity market remains relatively concentrated as
it has been vertically reintegrated among a few stakeholders after the initial privatisation
and divestment of the former state-owned industry.
i The early restructuring of the Bulgarian electricity sector
In the late 1990s, all sectors of the electricity industry (generation, transmission and
supply) were still owned and controlled by the state. The government decided to abandon
the centrally managed model in the electricity sector in 1999, at which point the ‘singlebuyer’
model was chosen as the most appropriate market structure to use in the initial
stages of transition. This was also an elective model under Directive 96/92/EC, which
was wisely seen as a precondition for EU membership at that time.
The National Electricity Company AD (‘the NEC’) was nominated to act as the
single buyer, and newly emerging independent power generators had to sell their output
to NEC; they could not sell directly to customers or supply companies as the NEC was
fully in charge of the centralised purchasing and selling. The NEC further incorporated
other activities such as transmission, distribution, supply, import and export of electricity,
thereby shaping a complete monopoly on the electricity market. Soon after the model’s
introduction, it was clear that generation capacity exceeded demand. The presence of
1 Yassen Spassov is an associate at Djingov, Gouginski, Kyutchukov & Velichkov.
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Bulgaria
excess capacity rendered the model inappropriate for the ‘market’ conditions in Bulgaria,
as this model is generally most effective in the diametrically opposite scenario. In
addition, the implementation of the single-buyer model was not by the book since no
effective restructuring of the market took place at that time (i.e., the design of trading
arrangements was delayed). These shortcomings and the transitional nature of the singlebuyer
model prompted a swift move away from the original structure of the market to
the current one.
ii Privatisation and unbundling
Privatisation was the next step. Most entities operating within the various sectors of
the electricity industry remained state-owned. Insofar as competition was unlikely to
grow in such environment, divestment of energy assets from the state monopoly NEC
became imperative. The privatisation of the energy sector was initiated in 2000 when
ownership of 11 small hydropower plants changed hands. As a result of lifting ownership
restrictions, most market participants have quickly become privately owned.
The privatisation of distribution companies was complete by 2004. Ownership
of the transmission grid, however, remained with the state. It is only the management of
the electricity system that has been functionally and legally separated from the NEC in a
newly established entity, the Electricity System Operator EAD (‘the ESO’). At the same
time, the privatisation and unbundling of distribution operators and supply companies
took place. The state initially divested only a majority shareholding interest in distribution
and supply companies and it remained a minority shareholder. As a result, three major
licensed distribution companies were created serving separate regions of the country. The
approach was standard. Insofar as distribution networks are naturally monopolistic, they
still had to be separated at privatisation stage from other competitive activities, such as
retailing. These formerly state-managed components of the electricity supply industry
were privatised and unbundled as completely separate lines of business, albeit into three
major vertically integrated undertakings: CEZ, E.ON and EVN.
In the course of restructuring, the state also decided to consolidate some of its
remaining assets into a vertically integrated undertaking – the Bulgarian Energy Holding
AD (‘the BEH’), which continues to be solely owned by the Ministry of the Energy,
Economy and Tourism. The BEH was incorporated in September 2008, bringing together
the two largest power generators (Kozloduy NPP and Maritsa East II TPP), the NEC
(now operating as a public supplier, owner of the transmission grid and electricity trader),
the ESO (now operating the transmission and distribution grids), a coal mining company,
the combined gas operator (Bulgartransgaz) and public gas supplier (Bulgargaz).
Whereas the major restructuring and privatisation stage has been largely
completed, ongoing transformation may still take place as Bulgaria is striving to adhere
to the requirements of European liberalisation. Notwithstanding the record of past
privatisation, key players remain under state ownership, such as the electricity system
operator (the ESO), a public provider and owner of the transmission grid (the NEC),
Kozloduy NPP and Maritsa East II TPP.
46

iii
The evolving legal framework
Bulgaria
The Energy Act 2003 was adopted at a fairly early stage of the restructuring of the
energy sector, and it sets out the legal foundation upon which the power, gas and heating
industries are currently all based. The statute lays down the general principles, rules and
institutional powers within the energy sector. To a great extent, it is perceived as the
overarching energy statute in Bulgaria, although recently the Energy from Renewable
Sources Act 2011 became the second most important regulatory grounds of the electricity
sector. 2 Secondary sources such as regulations, guidelines and decisions govern the details
of price regulation, licensing, interconnection to the grid and other matters. For example,
the State Energy and Water Regulatory Commission (‘the SEWRC’) is empowered to
pass rules on the management of the electricity system and distribution grids, trading
arrangements and safety standards. The SEWRC acts as a specialist supervisory and
enforcement authority in the power, gas and heating industry.
Alongside European legislation, the above statutes outline the legal framework on
electricity regulation in Bulgaria. The Energy Act 2003, however, falls short of reflecting
the latest EU requirements insofar as the Electricity Directive 2009/72/EC has, at the
time of writing, not yet been transposed into national law. 3
II
REGULATION IN THE ENERGY SECTOR
i Regulatory institutions
At the very inception of the reforms, public interest demanded a specialist regulatory
authority capable of protecting electricity customers; this had to be done against a
backdrop of investment in additional capacity, energy infrastructure and maintenance.
Policymakers struggled with the predicament to guarantee the independence of such
authority from corporate and other interests in the sector. The SEWRC was vested with
regulatory powers in the energy and water industries. It was established in September
1999, prior to the initial wave of reforms, and quickly underwent some refinement of
the initial statutory basis of its existence. 4
2 It should be noted that the Energy from Renewable Sources Act 2011 that is currently in force
repealed its predecessor, the Renewable and Alternative Energy Sources and Biofuels Act 2007,
which actually gave the strongest impetus to the renewable industry in Bulgaria.
3 The deadline for transposition was 3 March 2011. The amendment implementing the
Community provisions is currently pending before Bulgarian Parliament. As a preliminary
note, Bulgaria has elected to adopt the third model under Directive 2009/72/EC, the
independent transmission operator (‘ITO’) model, according to which transmission system
operators (TSOs) are allowed to remain part of integrated undertakings, provided they comply
with detailed rules on autonomy, independence and investment.
4 Please note that the Minister of the Economy, Energy and Tourism also has certain powers in
the energy sector, such as legislative competence (i.e., passing secondary legislation), planning,
tendering new capacity, monitoring and reporting to other institutions.
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Bulgaria
Pursuant to the Energy Act 2003, the SEWRC consists of seven members,
including a chairman. There are certain statutory preconditions for the eligibility
of members, such as qualifications and work experience, which should guarantee the
competent management of the authority; the Council of Ministers submits a proposal
to the prime minister who then appoints each member. The members of the SWERC
serve five-year terms and may not be reappointed after two consecutive terms in office.
In the course of their duties, members must be free from conflict of interest under the
Prevention and Establishment of Conflict of Interest Act. The Council of Ministers has
the power to dismiss members from office.
The powers that the SEWRC discharges in the energy and water industries
include:
a the adoption of trading arrangements for electricity and natural gas;
b the approval of general terms and conditions of certain contracts in regulated
industries;
c price regulation;
d licensing (i.e., issuance, modifications, supplements, termination and cancellation);
e determination of availability capacity for power generation in the regulated market;
f regulatory approvals related to financing of licensed undertakings;
g administrative supervision and control; and
h the hearing of complaints against the conduct of licensed undertakings.
SEWRC decisions are subject to judicial review by the Supreme Administrative Court.
The lodging of an appeal against a decision of SEWRC does not, however, suspend its
enforceability.
Policymakers are well aware that the creation of an independent authority
has not been a remedy to every problem, let alone those arising out of incomplete
liberalisation and lack of real competition. The Energy Act 2003, therefore, prescribes
guiding principles that the SEWRC is bound to follow in discharging its powers. The
principles lay down general objectives for the regulator and a roadmap for the industry’s
development. Accordingly, the SEWRC’s conduct is guided by the following:
a prevention of competition foreclosure on the energy market; 5
b balance of the interests between energy undertakings and their customers;
c equality between the separate categories of energy undertakings and customers;
d
e
the creation of efficiency incentives for the regulated industries; and
the creation of incentives for the development of a competitive market, where the
conditions for competition are found to exist.
ii Regulated activities: licensing and authorisations
In line with the early Electricity Directive 96/92/EC, two alternative ways are made
available for building new generation capacities: licensing and tendering. 6 Licence
5 The SEWRC may initiate proceedings before the Commission on Protection of Competition.
6 Recourse to a tendering procedure implies a lack of confidence that the market would deliver the
required investments. The Minister of Economy, Energy and Tourism has not held tendering
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applications shall be lodged before SEWRC, which is competent to rule on this matter
and prescribe conditions on the conduct of licensed undertakings. The Energy Act 2003
and the Ordinance on Licensing of Activities in the Energy Sector aim at establishing
objective, transparent and non-discriminatory licensing criteria for activities in the
energy sector. 7 Nearly all energy activities are licensed in Bulgaria, the most prominent
of which include power generation, transmission, distribution, supply on the wholesale
or retail markets, management and operation of the electricity system. 8
An energy licence is valid for a term of up to 35 years depending on the conditions
of the energy assets and the financial status of applicants. The licence may be further
extended for another period of up to 35 years. The SEWRC enjoys complete discretion
in assessing whether a licence applicant holds sufficient technical, financial and human
resources (as well as the relevant organisational structure). 9
iii Ownership and market access restrictions
Eligibility requirements for licensing
Only a limited number of entities are eligible to apply for a licence under the Energy
Act 2003. There are only two types of applicant that have standing to apply for a licence:
local companies incorporated in Bulgaria or companies registered in another Member
State of the EU or the EEA.
Entry restrictions
The Energy Act 2003 does provide express restrictions on the entry into certain sectors
of the electricity industry. For instance, only one licence may be issued for the following
activities:
a transmission of electricity (currently awarded to the NEC);
b management and operation of the electricity market (currently awarded to the
ESO);
c
d
public supply of electricity (currently awarded to the NEC);
management and operation of the electricity system (currently awarded to the
ESO);
procedures since the adoption of the Energy Act 2003.
7 Ordinance on Licensing of Activities in the Energy Sector was promulgated in State Gazette
No. 53 of 22 June 2004, last amended in State Gazette No. 19 of 6 March 2012.
8 Trading in natural gas is a notable exception, which does not require licensing. There are other
exceptions as the Energy Act 2003 introduces a bottom threshold of 5MW on certain activities.
Licensing is therefore not a prerequisite for activities falling below this threshold (i.e., this
concerns predominantly power or heat generation).
9 The commissioning of a nuclear power plant is made contingent on a decision of the Council
of Ministers that is based on proposal made by the Minister of Economy, Energy and Tourism.
A special permit and licence for the construction and operation of a nuclear power plant is
required in addition to a power generation licence. The Nuclear Regulatory Agency is the
competent authority discharging public powers in this sector.
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Bulgaria
e
f
distribution of electricity within a local region (currently awarded to the respective
distribution company: CEZ, E.ON or EVN); and
retailing of electricity or natural gas within a local region (currently awarded to
the respective end supplier: CEZ, E.ON or EVN).
Such restrictions are justified to the extent that they either prevent duplication of
monopolistic infrastructure (i.e., natural monopoly) or provide for centralisation and
coordination in the management of the market and the system as a whole (i.e., statutory
monopoly). As discussed below, there are further restrictions arising out of unbundling
requirements.
Ownership in the energy sector
The state continues to hold a substantial share of residual ownership in energy assets. Even
though most players on the energy market have become privately owned, privatisation
remains partial at best. As already noted, the state-owned BEH holds interest in the
transmission company (the NEC), the system operator (the ESO) and two incumbents
in power generation. Despite assertions that integration of activities does produce
benefits, in principle, this market feature may lead to foreclosure of certain segments
of the industry, especially where state-owned assets are more concentrated. Concerns
have been expressed that competition on the deregulated segment of the market may
have been limited due to high concentration of ownership. There have also been direct
accusations that profit maximisation resulting from vertical integration transcends
considerations of efficiency and operates to the benefit of monopolistic exploitation. 10 In
this context, the electricity trading industry has recently raised the issue that the licensing
procedure and state fees are too burdensome: trading and capital adequacy requirements
are so demanding that real competition on the market is limited.
iv Transfers of control and assignments
Regardless of the line of operation, be it generation, distribution or supply, the transfer
of control and assignment over regulated assets or mergers and acquisitions do require
regulatory approval throughout the life of a licensed energy undertaking. 11 The same
applies to day-to-day level of operation as the SEWRC reviews and approves certain
transactions on financing of licensed undertakings prior to their execution (e.g., loan
agreements or secured transactions). The acquisition of shares of a licensee is exempt
from regulatory review.
10 Kozloduy NPP, which is state-owned, has been blamed for creating of artificial deficits on the
internal energy market (deregulated segment). Doubts have been expressed that deficit may
have been created because of very poor coordination and forecast of demand.
11 For instance, corporate restructurings, such as mergers, spin-offs or split-offs do require a
regulatory approval, as well as winding-up or liquidation proceedings.
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Bulgaria
III
TRANSMISSION and DISTRIBUTION SERVICES
The underlying feature of the electricity reforms in Bulgaria has been the separation of
competitive from naturally monopolistic activities. According to this objective, power
generation and supply that are generally considered competitive were separated from
transmission and distribution, thereby promoting competition only where it is feasible;
transmission services have remained under state ownership as a natural monopoly. In
contrast, distribution services have largely been privatised as majority shareholding
interest is now held by private undertakings.
i Transmission and distribution operators
The most strategic component of the electricity system, the high and medium-voltage
transmission grid is owned by NEC. There are a significant number of large power
plants directly connected to the transmission grid. It is also a statutory requirement
that plants exceeding 5MW of installed capacity should seek interconnection to the
transmission grid, not the distribution grid. It is worth noting that the NEC is the
owner of the grid, but does not operate the grid, as this function has been reserved for
the ESO. Currently, the ESO is wholly owned subsidiary of the NEC that is legally and
organisationally separate from its parent company. The ESO and each of the distribution
grid operators are jointly responsible for the operational planning, balancing and control
of the electricity system.
In terms of medium and low voltages, Bulgaria has been divided into three
separate regions, 12 in which licensed distribution companies deliver electricity to retail
customers. The three major distribution networks are operated by CEZ Distribution
Bulgaria AD, E.ON Bulgaria Grids AD and EVN Bulgaria Distribution AD. Despite
corporate unbundling, these companies are vertically integrated with other undertakings
within the respective energy group licensed for electricity retailing and trading.
ii Unbundling
So far, only Directive 2003/54/EC (the Second Liberalisation Package) has been
implemented in Bulgaria. The Energy Act 2003 and secondary legislation allow only one
undertaking to be licensed for transmission services in Bulgaria and, as already noted,
this licensee is the NEC, the transmission grid owner. At the same time, the NEC is part
of the vertically integrated undertaking, BEH.
Furthermore, the Energy Act 2003 dictates that the operation of the transmission
grid be entrusted to an entity that does not hold another licence, and such entity shall
not be eligible to conduct another licensed activity. The ESO is, therefore, exclusively
in charge of transmission operations. The separation of the functions of transmission
services and operation of the transmission grid is designed to respond to the requirements
of Directive 2003/54/EC. Although the ESO is a wholly owned subsidiary of the NEC,
12 There are three major distribution areas: western Bulgaria, north-east Bulgaria and south-east
Bulgaria. There is a fourth area called Zlatni Pyasatsi, which is insignificant as it basically serves
a holiday resort.
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statutory safeguards have been created to guarantee the independence of the ESO
from the NEC as the latter acts in the capacity of a public supplier, power generator
and electricity trader. Overall, both undertakings (NEC and ESO) belong, directly or
indirectly, to the state-owned and controlled BEH.
In light of the foregoing, Bulgaria is falling behind the implementation of the Third
Liberalisation Package (i.e., Directive 2009/72/EC); the final date for its transposition
into national law was 3 March 2011. The unresolved problem that continues to pose a
problem is the fact that the NEC conducts power generation and public supply while it
is also an owner of the transmission grid and a parent company with respect to the ESO.
Directive 2009/72/EC clearly requires separation of transmission (including operation)
services from other activities.
A draft bill for implementation was passed at the first reading in Parliament
on 8 March 2012; there is no indication, however, when the second reading will take
place. 13 Provisionally, the compliance solution revolves around the transfer of ownership
over transmission assets from NEC (currently an owner of the transmission grid) to the
ESO (operator) and safeguarding the ESO’s independence in the context of the ITO
unbundling model.
Bulgaria is moving forward towards effective unbundling that will separate
transmission activities from power generation and public supply. The required autonomy
of the ESO is bound to become a fact sooner or later. The ESO will be equipped with
financial, technical and other resources enabling it to independently conduct transmission
activities. Transmission services will then fit into the framework of unbundling under
Directive 2009/72/EC.
iii Transmission and distribution access
Irrespective of the slow progress on unbundling, the Energy Act 2003 and secondary
legislation strictly adhere to the provisions of Directive 2003/54/EC. Access to
the transmission or distribution grid must be guaranteed under objective and
non‐discriminatory terms by implementing the model of ‘third-party access’. The entities
responsible for access to the grid are the ESO (for transmission) and the respective
distribution operator (CEZ, E.ON or EVN). Access may only be refused on grounds of
lack of capacity, where the provision of access would lead to technical problems, failing
grid security, or deterioration of the conditions of access for other grid users.
IV
ENERGY MARKETS
i Key market players to date
Many market participants are now privately owned companies, most notably in power
generation and distribution. The base load of electricity is delivered by the only operational
nuclear power plant in Bulgaria, Kozloduy NPP. The plans for a second nuclear plant in
Belene have recently been abandoned. In its place, there are plans to expand the capacity
13 To become binding law, a bill must be approved at two readings in Parliament and then
promulgated in the State Gazette.
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Bulgaria
of Kozloduy NPP. In terms of technology, coal power plants are most common. Midmerit
and peaking generation capacity is again provided by a number of coal power
plants around the country. Small and large-scale hydropower plants and pumped storage
provide additional capacity, even though their share is relatively small. Finally, the share
of renewable energy sources in final consumption is still falling behind in the energy mix,
despite the massive deployment of renewable energy plants in recent years.
On the wholesale market, the NEC acts in the capacity of a public supplier. 14
It supplies electricity to end suppliers and large customers directly connected to the
transmission grid. Retail supply of electricity is provided by three separately licensed
companies: CEZ Electricity Bulgaria AD, EVN Electricity Supply Bulgaria AD and
E.ON Bulgaria Retail AD (the structure is similar to that of distribution services).The
retail market consists of ‘captive customers’, namely households and small businesses. 15
Retail activities of the three energy groups have been unbundled from other activities
in the energy sector, even though they remain vertically integrated with other licensed
undertakings within the energy group they belong to (i.e., electricity distribution and
trading).
Finally, licensed companies may carry out electricity trading, separately from other
activities, in or out of the country. They are taking a growing share in the marketplace
since they are entitled to enter into electricity import and export transactions with
companies outside Bulgaria.
ii Development of energy markets
The Bulgarian energy market is currently in a transitional state between competition
and regulation; this status is best reflected in the trading arrangements between market
participants. The Energy Act 2003 and the Electricity Trading Rules (‘the Trading
Rules’) 16 set out the legal framework for transactions in the marketplace. Pursuant to the
newly adopted Trading Rules the electricity market in Bulgaria includes the following
interrelated elements:
a the market for electricity based on bilateral contracts;
b the organised market on the day preceding delivery (the day-ahead market);
c the balancing market; 17
14 The notion of a wholesale market is conditional as there is no clear-cut separation between
wholesale trading and retailing in Bulgaria.
15 In terms of ‘captive customers’, the Energy Act 2003 refers to households or businesses with
less than 50 employees, and with an annual turnover not exceeding approximately €10 million,
which have not selected another supplier and until such selection of another supplier has been
made. This provision, however, is not controlled and enforced in practice. Even larger businesses
may sometimes benefit from the status of a captive customer in order to avoid exposure to
higher prices on the deregulated segment of the market.
16 Decision No. 94 of 25 June 2010, promulgated in State Gazette issue No. 64 of 17 August
2010.
17 ESO operates and administers the balancing market as it executes transactions with registered
participants in order to offset nation-wide electricity system imbalances.
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d
e
the market for cold reserve and additional services; and
the market for the supply of intersystem capacity.
This outline is embedded in two parallel segments of the market: a regulated segment,
where SEWRC controls the prices and a deregulated segment where participants freely
negotiate prices. Accordingly, bilateral contracts that may be executed on both segments
are virtually the only means for executing transactions on the market. The day-ahead
market (deregulated segment) has not been started yet and a power exchange is wishful
thinking given the current state of the market. Transactions on the regulated market,
where NEC acts as a public supplier, prevail in the context of securing the public
service obligations of energy undertakings to supply captive customers with electricity.
The situation therefore largely resembles the model of the ‘single buyer’ with the only
exception that this concept is now confined to the regulated segment of the market.
Regulated segment
Bilateral transactions in electricity may be executed under regulated prices between the
following market participants:
a power generators and the public supplier (the NEC) or end suppliers (CEZ,
E.ON and EVN); 18
b the public supplier (the NEC) and end suppliers (CEZ, E.ON and EVN); 19
c the public supplier (the NEC) and the transmission and/ or distribution
companies for the purposes of meeting technological losses (CEZ, E.ON and
EVN);
d the end suppliers (CEZ, E.ON and EVN) and households, or small businesses with
less than 50 employees and with an annual turnover not exceeding approximately
€10 million.
Subject to regulation are also the prices for transmission of electricity through the
transmission and distribution grid, interconnection and access to the respective grid.
Deregulated segment
The Trading Rules further specify that transactions with electricity at freely negotiated
prices may be executed between power generators, electricity traders and customers
registered on the market. As already noted, transactions on the deregulated market are
presently confined to bilateral agreements.
18 In this case, power generators operate within the generation capacity reserved by SEWRC for
the regulated segment of the market (see infra, ‘Energy market rules and regulation’). Power
generation from renewable energy sources under preferential feed-in tariff is also included in
this section as feed-in tariffs are regulated by default.
19 In this case, the public supplier (NEC) sells electricity generated within the available capacity
of generators reserved by the SEWRC for the regulated segment of the market.
54

iii
Energy market rules and regulation
Bulgaria
Participation on the market, capacity regulation
Power generators must maintain generation capacity for the regulated segment of the
market in order to guarantee a secure and reliable supply of electricity to captive customers
(i.e., households and small businesses). How much of their capacity they should reserve
for the regulated market is decided by the SEWRC. Capacity availability quotas for
power generation on the regulated segment of the market are allocated annually among
independent power generators on the basis of a methodology approved by the SEWRC;
this is a unique feature of the Bulgarian energy market, whereby power generators are
ordered to share the burden of the semi-liberalised energy market and comply with
public service obligations. 20
First, the SEWRC builds a demand profile by collecting data from end suppliers
on the retail market. End suppliers submit demand forecasts in relation to the needs of
captive consumers. Distribution companies also submit demand forecast with regard to
technological losses of the grid.
On the other hand, the public provider (NEC) presents the load forecast under
long-term power purchase agreements with thermal power plants (i.e., AES Maritsa East
I TPP, Maritsa East II TPP and ContourGlobal Maritsa East III TPP) and the forecast
from power generation from renewable energy sources, including the forecast from its
own power generators (i.e., hydropower plants). The ESO also submits information
concerning the capacity availability of power generators for the period (i.e., information
about planned outages due to rehabilitation and maintenance), planned availability for
cold reserve, ancillary services, as well as statistical information on the participation
of the generators in the deregulated segment of the market for the previous regulated
price period. The figures submitted by NEC and ESO form the supply that needs to be
dispatched.
On the basis of the information received on supply and demand, the SEWRC
estimates the difference between the supply already provided and demand forecasts. The
positive difference is the further supply independent power generators need to produce
to meet captive customer demands. The SEWRC therefore approves a coefficient (‘Ki’)
representing the participation of each independent power generator on the regulated
segment of the market, and capacity availability quotas for power generation on the
regulated segment are accordingly allocated.
Pursuant to the Energy Act 2003 the allocation of individual capacity availability
quotas (i.e., coefficient Ki) must ensure that the burdens of the market liberalisation are
shared in a fair and just manner and that equal opportunities are provided to participate on
the deregulated segment of the market. The allocation of individual capacity availability
tends, however, to be ambiguous in practice. It is influenced by various economic factors
such as the price and costs of the respective independent power generator. There is a
20 The SEWRC runs a system that barely resembles the characteristics of a technical pool. In such
a system, power plants are principally dispatched in accordance with merit order based on their
cost of production. Albeit an unwritten rule, the SEWRC allocates more capacity availability
quotas to plants that have lower costs. Costs are, however, approved by the SEWRC.
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notable trend of approving higher individual capacity availability to power generators
with lower costs in order to preserve the low levels of the tariffs of the end suppliers. In
practice, it is very likely that power generators with higher costs may receive a reduced
number of allocated quotas, or even be left out without allocation, since the cost of
electricity generated would be too expensive to pass on to customers.
The spare capacity, which is not reserved by the SEWRC for the purposes of
regulated market, may be used for power generation on the deregulated segment of the
market, cold reserve or ancillary services.
Price regulation
Once capacity availability quotas are established, price regulation is the next issue that
features the interplay between the SEWRC on the one hand and power generation,
transmission, distribution and supply on the other. The Energy Act 2003 expressly
stipulates that price regulation must be non-discriminatory, objective and transparent.
Regulated prices are approved annually by the SWERC and they must enable energy
undertakings to recover economically justified costs and rates of return on capital.
Regulated prices may also be modified upon application for price adjustments in cases
of unpredictable changes of circumstances resulting in serious deviations of the actual
costs for operation and deterioration of the financial standing of an energy undertaking.
As noted, the SEWRC makes an assessment of the economic justification of the
costs for licensed activities on the basis of data submitted by regulated undertakings,
its own assessment and comparative analysis of national and international practices.
Understandably, certain types of costs are not taken into account, such as costs related
to the sale of electricity on the deregulated segment of the market, costs not related to
licensed activities, administrative sanctions and penalties. Regulated prices may, however,
compensate for stranded costs as a result of investments related to the transition to a
competitive market or public interest obligations imposed on a power generator (i.e.,
related to security of supply, environmental protection and energy efficiency).
The twin function of regulation (i.e., protection of the interests of customers and
energy undertakings) is discharged by two primary methods of price regulation: rate of
return on capital (cost plus) and incentive-based regulation. The second method may
take the form of ‘ceiling on revenues’ or ‘ceiling on prices’. The regulatory regime in
Bulgaria combines these methods altogether.
The method of regulation for power generation and transmission that is currently
employed by the SEWRC is the rate of return on capital. 21 The SEWRC allows power
generation to recover approved cost of production and a reasonable rate of return that
may vary from 1.7 per cent for nuclear plants to 12 per cent for thermal plants (for
2011–2012). Transmission is also subject to rate-of-return regulation (i.e., 6.54 per
cent for 2011–2012). On the other hand, the ceiling on revenues method is applied to
distribution and end supply. 22 Evidently, there is an interesting division in the way the
21 Please note that the formation of feed-in tariffs for renewable energy is slightly different (see
Section V, infra).
22 The SEWRC is entitled to adopt a new approach and change the methods.
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prices for transmission and distribution services are determined. The former are based
on rate of return, whereas the latter on incentive-based regulation. The division may be
further traced to rates charged for access to the respective grid. Access to the transmission
grid (by the ESO) is also under the rate-of-return model. Surprisingly, access to the
distribution grids is again subject to incentive-based regulation (ceiling on revenues)
within the framework of distribution services.
iv Market developments
It is evident that the Bulgarian electricity sector remains heavily regulated. More than 70
per cent of the total electricity generated continues to be traded in the regulated segment
of the market. Strong competition has not been observed in the deregulated market either,
where Kozloudoy NPP and Maritsa East II TPP (both state-owned companies) enjoy a
rather dominant position. Other market participants, such as Sviloza and EnergoPro,
have managed to take up a very small share of the deregulated market.
The pace of expanding the deregulated segment of the market is too slow to
expect any tangible differences in the foreseeable future. It has been estimated that the
deregulated segment grows by approximately 2 per cent per year.
V
RENEWABLE ENERGY
Bulgaria adopted its first preferential purchase price (feed-in tariff) for electricity produced
from renewable sources and combined heating in 2005. Feed-in tariffs have been
determined annually by the SEWRC ever since. The Renewable and Alternative Energy
Sources and Biofuels Act 2007 was the first statute to institutionalise renewable energy
incentives. It guaranteed priority in interconnection for renewable energy power plants,
mandatory purchase of electricity under long-term power purchase agreements and, most
importantly, favourable feed-in tariffs that provided for a generous rate of return.
An unprecedented expansion of installed capacity based on renewable energy
followed as a result. Developers of renewable energy soon faced a critical obstacle: old
and underdeveloped grid infrastructure. In certain parts of the country, the transmission
grid has become systemically overloaded, and the ESO had to intervene and suspend or
restrict access to the grid due to insufficient transmission capability. Efforts to replace
obsolete infrastructure have been modest by far and sometimes perfunctory. The scale
of rehabilitation and expansion of the grid to the extent necessary for integration of
the already existing installed capacity entails significant financial commitment that
the transmission and distribution companies have not been willing to undertake. For
instance, the so‐called Dobrich Ring has been scheduled for rehabilitation as one of the
most critical points of the transmission grid, but nevertheless very little has been done to
improve the situation. 23
Meanwhile, expansion of renewable energy caused another significant consequence
– a substantial increase in retail electricity prices. Feed-in tariffs are passed on as a ‘green
23 Recently a large cluster of wind power plants have been connected to substations part of the
Dobritch Ring in north-east Bulgaria.
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energy’ charge in electricity bills. Furthermore, the intermittency of wind also requires
more balancing capacity, which adds extra expense by definition. Policymakers considered
these calculations may render electricity to customers prohibitively expensive. Electricity
prices and the problems of the grid were the two most obvious reasons for the policy
turn around in early 2011. 24 A new law was passed before Parliament, which drastically
changed the landscape for the development of renewable energy plants. The new Energy
from Renewable Source Act 2011 introduced a new procedure for interconnection, as a
number of preparatory steps will now precede the previous interconnection procedure.
In general, the regime for renewable energy has become a bit more restrictive.
i Coordination and approval of available capacity for interconnection
The most notable change affects the interconnection procedure. The ultimate objective
is to avoid an excessive number of applications for interconnection at random points
on the grid that may cause overloading. Coordination and planning of interconnection
will enable efforts on grid rehabilitations and expansion to be concentrated. For this
purpose, transmission and distribution capacity for interconnection will be planned and
investment programmes for interconnection will be coordinated between the Ministry
of Economy Energy and Tourism, the grid operators and the SEWRC. The maximum
capacity for interconnection is ultimately approved by the SEWRC, which determines
the total assigned capacity for interconnection together with designated zones and
permissible voltage levels annually by 30 June.
Power generators must submit applications for assigned generation capacity on an
annual basis in order to connect to the grid. Applications may be submitted as early as
1 July 2012 to the transmission grid operator or the respective distribution grid operator.
Applications are ranked on a first-come, first-served basis until available capacity for
interconnection has been utilised. Approved applicants will receive a statement on the
conditions for interconnection. Whenever the overall capacity applied for by powergeneration
companies exceeds the total capacity for a designated zone, determined by
the SEWRC, any further applications shall be rejected until the respective grid has been
expanded or rehabilitated.
ii Feed-in tariffs and power purchase agreements
The new Energy from Renewable Sources Act 2011 provides that feed-in tariffs will
remain fixed for the entire validity of power purchase agreements, except for electricity
generated from biomass. Under its predecessor, tariffs were determined on an annual
basis. The new provision will certainly shed more light and transparency for investors.
The specific feed-in price that will be applied to a new power generator will be the feed-in
price determined by the SEWRC at the time of putting the power plant into operation.
Prices in real terms either remain more or less the same (i.e., for wind power) or have
drastically fallen (i.e., for solar power). The SEWRC explained the reason for the falls in
price by asserting that the lower prices reflect lower capital costs.
24 The formal reason for the new statute was the implementation of Directive 2009/29/EC.
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In terms of formation, feed-in tariffs represents a unique fusion of rate-ofreturn
regulation and incentive-based regulation. Tariffs consist of two components: a
percentage of the average sale price of the end suppliers (‘ceiling on revenues’) and a
premium customised according to the energy source (‘rate of return’). The first component
amounts to at least 70 per cent of the average sale tariff of the end suppliers (CEZ, E.ON
and EVN) for the previous calendar year. In addition, a premium is determined by the
SEWRC on the basis of the type of the primary energy source for power generation
(wind, solar, biomass, etc). No minimum thresholds for the premium are specified. 25
Alongside the sophistication of feed-in tariffs, another aspect of incentive
regulation has been adjusted. In particular, the terms of power purchase agreements
(‘PPAs’) for electricity from renewable sources have been reduced to the following:
a 20 years for electricity generated from solar or geothermal power, as well as from
biomass;
b
c
12 years for electricity generated from wind energy; and
15 years for electricity generated from hydropower plants of up to 10MW
installed capacity and all other types of renewable energy sources.
iii The future of feed-in tariffs
The Energy from Renewable Sources Act 2011 contains a provision that incentives
for additional renewable energy will be discontinued from the date on which the
Minister of the Economy, Energy and Tourism reports that the national target has been
achieved. Pursuant to Directive 2009/29/EC, Bulgaria has been assigned a target of 16
per cent renewable energy in final consumption by 2020. State officials and industry
representatives constantly disagree on the actual percentage of renewable energy already
achieved in final consumption. The problem largely comes from the fact that large-scale
hydropower also counts towards this target, which could greatly affect calculations. 26
iv Electricity from biomass
Electricity from biomass is somewhat an exception from the generally restrictive outlook on
renewable energy. The validity of PPAs for mandatory purchase of electricity from biomass
has actually been extended to 20 years from the previous 15-year term under the repealed
statute. Feed-in tariffs generally remain constant for the entire duration of the PPAs, except
for electricity from biomass, which is subject to indexation. The indexation mechanism
should reflect any changes in value of the following costs factors: costs for feedstock for
power generation, costs for transportation fuels and employment-related costs.
Furthermore, an entirely new Forests Act 2011 entered into force. One of the
objectives of the newly passed act is an increase of the timber yield in the context of
preserving the natural timber stocks and guaranteeing sustainable economic development.
25 Feed-in tariffs must reflect the following cost factors: type of renewable source; technology,
installed capacity, location; investment costs; structure of the venture capital and the investment;
efficiency of the plant; operational costs and rate of return on capital.
26 Most of the large hydropower plants were commissioned before 1989 and they fall outside the
scope of the feed-in tariffs.
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State enterprises and municipalities – owners of forest lands, may execute agreements for
timber yield or sale of timber. The maximum statutory term of such agreements may be
up to 15 years; however, annual quantities of timber available for use – the subject of
the agreements – must not exceed certain quantities of the annual use of timber by the
contracting state enterprise or municipality.
VI
THE YEAR IN REVIEW
Some key events that took place in the course of 2011 and early 2012 include the
following:
a The Renewable and Alternative Energy and Biofuels Act 2007 was repealed and
replaced by the Energy from Renewable Sources Act 2011 (May 2011) .
b The American private equity Contour Global acquired 73 per cent shareholder
interest in Maritsa East III TPP (at the end of 2011). The new owner contemplates
investments mainly in environmental protection and better labour conditions in
the power plant. Expansion of generation capacity is also under consideration.
c EVN acquired the residual share of the state (approximately 33 per cent) in
distribution (EVN Bulgaria Electricity Distribution AD) and end supply (EVN
Bulgaria Electricity Supply AD). The constituents of the vertically integrated
undertaking are almost exclusively owned by the majority shareholder EVN.
d Disposal of minority state shares (approximately 33 per cent) in other distribution
companies (CEZ and E.ON) have been postponed. The Minister of Finance also
announced that minority shareholder interest in BEH (holding NEC, ESO,
Kozloduy TPP, Maritsa East II, Bulgartransgaz, Bulgargaz, etc) would be offered
on stock exchange markets. Details of these plans are not yet clear. On 5 April
2012, opposition members of Parliament submitted a draft bill proposing a total
ban on the sale of state assets.
e Energo-Pro AS (Czech Republic) acquired E.ON Bulgaria AD, the parent
company of the E.ON vertically integrated undertaking that includes majority
shareholding in E.ON Bulgaria Grids AD (distribution operator), E.ON Bulgaria
Sales AD (end supplier) and E.ON Energy Services EOOD (electricity trader).
f The commissioning of a new nuclear power plant in Belene was officially
abandoned (March or April 2012). The Belene plant that was approved by the
EC Commission in 2007 was expected to deliver reasonable electricity prices
and security of supply against the background of scheduled retirement of coal
generation capacity in the next few years. The plans for additional nuclear capacity
will be partly fulfilled as the government is currently contemplating an additional
unit at Kozloduy NPP.
VII
CONCLUSIONS and OUTLOOK
The creation of a genuinely competitive market is still an abstract objective that
policymakers will frequently employ in their rhetoric; however, insofar as the state
of the market affects the overall competitiveness of the economy, further measures
on liberalisation are inevitable in the foreseeable future. The general problem with
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regulation is that, although its purpose is to protect public interest and promote
economic efficiency, it can also induce distortions of its own that may affect pricing, cost
reductions, investment decisions.
Since the first steps of liberalisation, the government in power has demonstrated
its intention of avoiding a simple transfer of assets from public to private hands without
being able to guarantee competition or at least to adequately protect market participants
– and most of all customers – from market failures. For this reason, the market in
Bulgaria has become increasingly complex and somehow became stranded in the current
transitional state (i.e., in between competition and regulation). Notwithstanding,
the incidence of continuous state ownership and heavy regulation, the free market is
expanding along these lines as trading on the deregulated segment and electricity exports
of electricity are regular.
On the other hand, renewable energy capacity has been continuously growing.
Regardless of the policy change on renewable energy, the utilisation of renewable
potential will not be impeded; it will merely be channelled through the realities of the
market – customers are not able to carry the increasing burden of a rapidly growing
renewable sector. The expansion of renewable energy will be controlled, but certainly not
abandoned, as policymakers realise Bulgaria’s commitments on sustainable development
and the invaluable benefit of security of supply.
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Chapter 5
Canada
Patrick Duffy, Brad Grant, Erik Richer La Flèche and Glenn Zacher 1
I
OVERVIEW
Canada is a federal state comprising 10 provinces (Alberta, British Columbia, Manitoba,
New Brunswick, Newfoundland and Labrador, Nova Scotia, Ontario, Prince Edward
Island, Quebec and Saskatchewan) and three territories (Northwest Territories, Nunavut
and the Yukon). The respective powers of the various levels of government are set out in
the Constitution Act 1982.
Canada is a common law jurisdiction, with the exception of the province of Quebec,
which operates under the Civil Code of Quebec. Each province has its own provincial
court of general jurisdiction and an appellant court. The jurisdiction of Canada’s Federal
Court is limited to specific matters under federal jurisdiction and appeals or judicial review
applications from federal tribunals. Canada operates a unitary system of courts in which all
cases can ultimately be appealed to the Supreme Court of Canada.
The provinces have primary responsibility for energy regulation through their
jurisdiction over local works and undertakings, non-renewable natural resources and
electrical energy. The provinces exercise jurisdiction through legislative enactments,
various forms of delegated legislation and through independent energy and utility
commissions. Provincial legislation and tribunals also govern most environmental
matters pertaining to the development of energy projects.
The federal government has jurisdiction over international and inter-provincial
trade and commerce, which includes authority over international and inter-provincial
transmission lines and energy exports. The federal government also has jurisdiction over
nuclear safety, aboriginal affairs, and a number of environmental matters that affect
energy projects.
1 Patrick Duffy, Brad Grant, Erik Richer La Flèche and Glenn Zacher are lawyers in Stikeman
Elliott LLP’s Energy Group.
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For purposes of expediency, this chapter will discuss the regulation of energy at a
general level with illustrative examples drawn from various Canadian jurisdictions.
i Canadian energy sector
Electricity
The power sector in Canada is principally regulated by the provinces and markets are
regional in nature. Most electricity trade is intra-provincial or north–south, between
provinces and neighbouring US states; there is relatively little east–west trade between
provinces.
Two provinces, Alberta and Ontario, restructured their electricity markets, albeit
with differing success. In the mid-1990s, Alberta deregulated generation, mandated open
access for regulated transmission and distribution and introduced a real-time electricity
spot market. Alberta now has a fully competitive wholesale and retail electricity market.
In 1998, Ontario unbundled transmission, generation and dispatch, and in 2002 it
introduced fully competitive wholesale and retail markets. Deficiencies in Ontario’s
market design and a confluence of other market conditions and political pressures,
however, brought about a partial closing of the Ontario market. Today, Ontario operates
under a hybrid structure where there is nominally wholesale and retail competition, but
a large amount of generation remains regulated or subject to long-term governmentbacked
contracts. The remaining provinces have more traditional government-owned
vertically integrated utility structures, which offer bundled services at regulated rates.
Some provinces – for example, British Columbia, Quebec and Nova Scotia – have limited
generation opportunities for independent power producers, largely in the renewable
sector.
The most significant developments in the power sector centre on investments
in renewable or clean generation and infrastructure renewal and upgrades. Two years
ago, Ontario launched the most ambitious renewable feed-in-tariff (FIT) programme
in North America. Other provinces have followed suit, albeit on a smaller scale. A
number of provinces are also investing in and constructing major transmission and
other infrastructure to facilitate economic and resource development, access renewable
resources (wind, hydro) and facilitate export to the United States. Alberta and Ontario
have launched competitive processes to develop major transmission projects, which are
attracting foreign companies.
Natural gas
The Canadian gas sector, by comparison, has traditionally been characterised by more
national east‐west trade. Most gas production is in the western Canadian sedimentary
basin and gas is shipped via inter-provincial pipelines to eastern Canada and the northeast
United States. Recent non-conventional shale gas discoveries in the midwestern and
north-east United States are transforming the Canadian gas industry. Natural gas prices
have plunged in North America, west-to-east pipeline throughput has substantially fallen
and plans are underway to satisfy eastern Canadian demand from the United States.
As a result, western Canadian producers are eyeing opportunities for new markets and
making plans to export liquefied natural gas (‘LNG’) to Asian markets from Canada’s
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west coast. This will require the development significant infrastructure to transmit the
natural gas to the west coast, liquefy it and ultimately ship the LNG to foreign markets.
Oil
As is the case with natural gas, the majority of Canadian oil production is in the Canadian
sedimentary basin. In particular, Alberta’s oil sands contain some of the world’s largest oil
reserves. These reserves have been attracting significant investment and, as a result, the
forecast is for a steep increase in Canadian oil production. The vast majority of Canadian
oil production is exported via international pipelines to the midwestern United States;
however, there is currently a significant price differential between the price paid for oil
delivered to the Midwest (West Texas Intermediate) and the world oil price (Brent).
In order to access the world price for Canadian oil, pipelines are being proposed that
will connect Canadian production with hubs that provide for export outside of North
America and thereby attract world oil prices. One such proposal is TransCanada Corp’s
Keystone XL pipeline. Keystone XL was recently denied a Presidential permit by the
United States, which has stalled its development. TransCanada is working on reviving
the project, but in the meantime a second pipeline, Enbridge Inc’s proposed Northern
Gateway oil pipeline, is being proposed to connect Alberta production with Canada’s
west coast for export to the Asia-Pacific markets. Such access to Asia-Pacific markets
would fundamentally change the balance of future oil trade between Canada and the
United States.
II
REGULATION
i The regulators
The National Energy Board (‘the NEB’) establishes regulatory policies for energy matters
under federal jurisdiction. The primary area of NEB’s activity is the regulation of Canada’s
interprovincial oil and gas pipelines owned by TransCanada Pipelines Limited and
Enbridge Pipelines Inc. The NEB also has regulatory responsibility for the construction
and operation of international transmission lines and the export of natural gas, oil and
electricity.
Provinces have authority over the exploration and development of energy
resources. This function may be assigned to an independent regulatory tribunal (e.g.,
Alberta’s Energy Resources Conservation Board) or may be under the direct control
of a government ministry. Oil and gas exploration in frontier and offshore areas are
regulated either by bodies created by federal or provincial management agreements (e.g.,
the Canada–Newfoundland and Labrador Offshore Petroleum Board) or by the NEB.
Canada’s energy sector is also regulated by provincial utility regulators that are
responsible for facilities that lie completely within the borders of any single province.
This jurisdiction can include diverse matters such as facility siting, rate setting, utility
divestitures, retail issues and consumer complaints. In some provinces, energy regulators’
authority is limited to responsibility for energy resources and energy utility regulation
(e.g., the Ontario Energy Board); in other provinces, utility regulators also have
jurisdiction over other sectors such as automobile insurance, railways and water utilities
(e.g., Nova Scotia Utility and Review Board).
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Energy and utility commissions are established through federal or provincial
legislation and their members are appointed by the relevant government, usually for fixed
terms. They act as quasi-judicial tribunals, independent of the businesses they regulate.
Although in large part they exercise their powers free of interference from government,
their jurisdiction is set out in legislation that may be amended by the relevant legislature.
By statute, some tribunals are also subject to direction from provincial or local
governments. These tribunals generally exercise their powers through policy instruments
(such as codes, rules and generic decisions), licensing authority and individual decisions.
The decisions of Canadian regulatory tribunals are generally subject to appeal
or judicial review by the courts – the Federal Court in the case of the NEB and other
federal bodies, and the provincial superior courts in the case of provincial energy and
utility commissions. In some jurisdictions the right to appeal is not automatic but
requires leave of the court. Appellate judicial review is generally limited to questions
of law or jurisdiction, procedural unfairness, bad faith or unreasonableness on the part
of the regulator. Federal and provincial courts tend to give deference to regulators on
matters of law that are intertwined with economic policy and rate setting that lie within
a regulators’ area of expertise, but give less deference on matters of law that are of general
importance.
There is also federal and provincial jurisdiction over anti-competitive practices
in the energy sector. The Competition Bureau reviews anti-competitive practices, both
criminal and civil, under the federal Competition Act. Criminal offences are prosecuted
by the Attorney General before the criminal courts; the federal Competition Tribunal
has the power to issue remedial orders for reviewable civil matters (e.g., abuse of
dominance and tied selling). At the provincial level, bodies such as Ontario’s Market
Surveillance Panel and Alberta’s Market Surveillance Administrator monitor activities
within competitive energy markets and the conduct of market participants to identify
abuses of market power, gaming and market deficiencies or design flaws.
ii Regulated activities
At the federal level, approval from the NEB is required to construct and operate an
interprovincial or international oil and gas pipeline, an international power line or any
inter-provincial power line designated by the federal government, and any additions to
an existing pipeline or transmission line that is under federal jurisdiction. In determining
whether a project should proceed, the NEB reviews, among other things, its economic,
technical and financial feasibility, and the environmental and socio-economic impact of
the project.
The NEB regulates tolls and tariffs for oil and gas pipelines under its jurisdiction
to ensure they are ‘just and reasonable’ and that there is no ‘unjust discrimination’ in
tolls, services or facilities. Pipelines under the Board’s jurisdiction are divided into two
groups that tailor the degree of financial regulation to the size of the regulated operations.
Group 1 consists of major oil and gas pipelines, which are generally subject to ongoing
regulatory oversight by the NEB. Some smaller Group 1 facilities and Group 2 pipelines
are regulated on a complaint basis.
The NEB also regulates the export and import of energy. The export and import
of natural gas is authorised under either long-term licences of up to 25 years (which
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require a public hearing and approval by the federal Cabinet) or short-term orders for
a maximum of two years. Oil exports are authorised by short-term orders for periods
of less than one year for light crude oil and less than two years for heavy crude oil.
With respect to electricity, the NEB has issued permits and licences for as short a period
as three months and for as long as 30 years, with the average being for 10 years. In
reviewing applications for electricity exports, the NEB applies a ‘fair market access’
policy under which exporters must afford Canadian purchasers who have demonstrated
an intention and ability to buy electricity for consumption in Canada an opportunity to
purchase electricity on terms and conditions as favourable as those offered to an exporter
customer. The NEB does not regulate imports of oil or electricity.
Provinces regulate oil and gas pipelines and facilities that lie completely
within their borders; this includes regulatory authority over the construction of new
infrastructure and the setting of ‘just and reasonable’ rates for service. Electricity
generation, transmission, distribution and sale are all broadly regulated. Licences to
generate, transmit, distribute or sell electricity are required from provincial regulatory
authorities. Approvals or permits to construct generation, transmission or distribution
facilities must also be obtained from provincial energy commissions or from a variety of
provincial and municipal authorities. Rates for transmitting and distributing electricity
are also set by provincial regulators, as is generation in the case of those provinces with
vertically integrated structures.
In addition, a range of other authorisations may be required from federal,
provincial and local authorities. These will vary depending on the facility’s scale, physical
location, fuel type, discharge characteristics and the potential environmental effects. For
major projects, the most significant approvals required are generally under federal or
provincial environmental assessment legislation. The environmental assessment process
may be consolidated or coordinated with the project approval process, although this can
vary depending on the type of project and jurisdiction involved. Provincial approvals
are often required for air and noise emissions, water intake and discharge, storm sewer
management, archaeological assessment and for decommissioning and clean-up of
contaminated sites. Local land use approvals required may include official plan and
by‐law amendments, sewer use, building permits and servicing easements. In April 2012,
the federal government introduced a plan to streamline the federal project approval
process and better coordinate it with provincial processes.
Section 35 of the Constitution Act 1982 provides protection to the aboriginal
and treaty rights of Canada’s aboriginal peoples. The courts have interpreted this section
as placing a duty upon the government to consult with aboriginal peoples where
approval of a project could affect an aboriginal or treaty right. While the duty belongs
to the government, in practice responsibility for consultation is often delegated to the
proponent. In some cases where the impact upon a right is significant, a proponent may
be required to accommodate the right. The courts have ruled that regulators may assess
whether the duty to consult has been satisfied when issuing an approval, although the
scope of that assessment depends on the nature of the particular approval being sought
and the stage of the project. For example, an economic regulator might assess the duty as
it relates to the issues that are within the regulator’s mandate and not the entire project.
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Canada
Ownership and market access restrictions
The requirements to obtain a licence and licensing conditions vary depending on the
sector involved and the type of activity that is the subject of the licence.
Those segments of the energy industry that are economically regulated are subject
to restrictions designed to eliminate the risk of market dominance and improper crosssubsidisation
of competitive business at the expense of captive ratepayers. For example,
there are restrictions in the electricity and gas sectors that prohibit regulated transmitters
and distributors from operating other competitive businesses. A shareholder is generally
permitted to own both competitive and regulated entities, although in those cases the
regulated entities will be subject to transfer-pricing provisions to ensure transactions
with affiliates are at fair market value. There may also be limitations on employee and
information sharing between regulated and unregulated affiliates.
Acquisition of control of a Canadian business, whether or not currently foreignowned,
by a non-Canadian investor requires review (generally pre-closing) or notification
(post-closing) under the Investment Canada Act. A transaction will be reviewed if it meets
certain asset thresholds. Reviewable transactions may not be completed until the Minister
of Industry Canada has found that the proposed transaction will be of ‘net benefit’ to
Canada. While the federal government has generally welcomed foreign investment, in
2010 the federal government exercised its authority to block the acquisition of PotashCorp
by BHP Billiton because it failed the ‘net benefit’ test. Since then, however, all reviewable
foreign investments have been approved and the PotashCorp case does not seem to have
materially deterred foreign investment. As a general rule, Canadian provinces do not
limit the acquisition of interests in the energy sector by foreign companies, although the
potential exists for restrictions and conditions to be imposed if regulatory approval of a
transaction is required.
iv Transfers of control and assignments
While the particular requirements vary by sector and jurisdiction, a regulator’s approval is
generally required before a regulated entity can issue any stocks or bonds, or dispose of or
encumber a significant part of its facilities. A regulator must also approve any change in
control of voting securities or any merger with or acquisition of another regulated entity.
In deciding whether to approve a particular transaction, the regulator must consider the
public interest and the continued financial stability of the regulated entity. The time to
obtain approval depends upon the complexity of the transaction and ranges between
several weeks and a few months.
The transfer of oil and gas interests in Crown leases, and licences for wells, pipelines
and facilities, is regulated by the respective government in each provincial jurisdiction.
Typically, the transfer of a licensee’s rights must be approved by a provincial regulatory
body. The regulatory body will assess the licensee’s and licensor’s creditworthiness and
will assess the exploration or production site prior to approving the transfer of the licence.
Mergers, acquisitions or changes of control may also be reviewable under both
federal and provincial legislation. The federal Competition Act establishes mandatory
pre-merger notification for mergers meeting certain financial thresholds and if notifiable,
the merger cannot be completed for specified no-close periods. The Competition Bureau
reviews mergers and may challenge a transaction before the Competition Tribunal.
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Competition Bureau review can take, generally speaking, from one to five months or
more depending on the complexity of the competition issues. Following expiry of the
no-close period, the merging parties are free to close unless the Competition Tribunal has
enjoined the transaction because of a finding that a merger would prevent or lessen (or
likely prevent or lessen) competition substantially, but in practice most merging parties
only close upon receipt of an affirmative clearance from the Competition Bureau.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Canada has had a competitive interprovincial natural gas market since 1 November
1986. The genesis of this was an agreement between the federal government and the
three western gas-producing provinces of British Columbia, Alberta and Saskatchewan
(commonly referred to as the Halloween Agreement). Consumers can purchase natural
gas directly from producers or indirectly through arrangements with local distributors.
While there is some overlapping ownership, the production, transmission and distribution
segments of the market are generally disaggregated.
The nature of Canada’s electricity market is more complex. The provinces
of Alberta and Ontario have restructured their electricity markets and unbundled
generation, transmission, distribution and retail services. Other provinces have
functionally unbundled some services, but public ownership and vertical integration
remain common.
In Ontario, virtually all transmission remains in hands of the government-owned
transmitter Hydro One Networks Inc (which owns and operates more than 95 per cent
of the transmission in Ontario). The province, however, recently launched a competitive
process to designate a transmitter to develop a major new transmission project; this may
be followed by further competitive processes for other transmission projects. Ontario’s
distribution sector is highly fragmented, with over 80 local distribution companies;
there are opportunities for consolidation and private sector investment in this area. In
April 2012, the Ontario government initiated a review to examine removing barriers and
encouraging consolidation.
In Alberta, the provincial transmission system is owned by a number of utilities
(known as transmission facility owners or ‘TFOs’). The Alberta Electric System Operator
(‘the AESO’) contracts with the TFOs to acquire transmission services. The AESO
oversees the design and use of the transmission system to ensure fair market rates, nondiscriminatory
access for all market participants and the safe reliable operation of the
system. The Alberta Utilities Commission (‘the AUC’) approves the costs for transmission
facility owners to provide their services. The regulated costs of the transmission companies
are passed on to the AESO, which recovers the cost of operating the system and the
transmission companies’ costs through the AESO’s transmission tariff, which is also
approved by the AUC. Like Ontario, Alberta has initiated a competitive process to select
transmitters to develop several major new transmission lines. The distribution system
remains regulated, with distribution tariffs being approved by the AUC. The majority
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of distribution systems are owned by municipally owned utilities, rural electrification
associations or local cooperatives.
In the other provinces, government-owned utilities own most transmission
assets, with distribution in provincial or municipal hands. In Quebec, for example,
Hydro‐Québec’s TransÉnergie division owns and operates the provincial transmission
grid under open-access rules and regulated tariffs. Hydro-Québec Distribution has the
exclusive right to distribute electricity at regulated rates throughout the province with
very limited exceptions.
ii Transmission/transportation and distribution access
Distributors of natural gas and transmitters and distributors of electricity generally enjoy
the exclusive right to serve a particular territory. These exclusive rights can be conferred
through franchise agreements with municipal governments or by way of specified service
territories or facilities prescribed in a utility’s licence. A competing utility will not be
permitted to operate in an exclusive franchise area without regulatory approval. It should
be noted that Canadian natural gas transmitters typically do not enjoy exclusive franchise
rights.
In exchange for exclusive franchise rights, transmitters and distributors in Canada
are legally obliged to connect and serve third parties that lie within their franchise area
upon request. These obligations are rooted in the ‘common carrier’ doctrine that Canada
adopted from English common law. The obligations to connect and serve are generally
prescribed by statute and are typically enforced by regulators through codes and licensing.
For example, Sections 28 and 29 of Ontario’s Electricity Act 1998 require an electricity
distributor to connect a ‘building that lies along any of the lines of the distributor’s
distribution system’ and to ‘sell electricity to every person connected to the distributor’s
distribution system’.
The obligations to connect and serve are not absolute. A utility is entitled to
recover the reasonable costs to connect a third party and is not required to continue
to provide service to a customer that has failed to pay its bills. The precise parameters
of these obligations are spelled out in regulations, codes, regulatory decisions and the
utility’s conditions of service. A corollary of the obligations to connect and serve is that
transmitters and distributors must provide third parties with non-discriminatory access
and cannot favour a particular category of customer. This principle, however, can be
modified as illustrated by recent legislative changes in Ontario that direct electricity
transmitters and distributors to provide preferential access to renewable generators.
iii Rates
Rates for transmission and distribution services in Canada are generally set pursuant to
rate proceedings before federal or provincial regulatory tribunals. In some cases, rates may
be set by the provincial Cabinet, or in the case of some municipally owned distribution
systems, by the municipal council.
Where rates are set by a regulatory tribunal, transmitters or distributors are
required to submit applications requesting rates and providing evidence to support the
underlying revenue requirement (including a return on investment). Customers and
other interested parties are provided with an opportunity to intervene and challenge the
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company’s projected revenue requirement. The application may proceed to a full costof-service
hearing before the regulator, although often many of the issues are resolved
through negotiated settlements with intervenors prior to a hearing.
When considering an application, the regulators’ mandate is to set a rate that
is ‘just and reasonable’ to both utility owners and consumers. The concept of just and
reasonable rates is well-established in Canadian law and the concept can be found in most
statutes that govern rate-regulated entities. Canadian regulators are generally granted
wide discretion over the methodology used to calculate a just and reasonable rate.
Canadian law requires that the resulting rate must be sufficient so that the utility’s
shareholders can earn a ‘fair return’ upon their capital investment (i.e., as large a return
on the capital invested in the company as the investor would receive if it were investing
the same amount in other securities possessing an attractiveness, stability and certainty
equal to that of the company). The rate of return is composed of a return on equity and
cost of debt and may be set by a regulator in a generic proceeding to ensure consistency
between all of the entities it oversees.
Various Canadian regulators have experimented with performance or incentive
ratemaking and automatic adjustment formulas in an effort to limit full cost-of-service
rate proceedings.
iv Security and technology restrictions
Oil and gas pipelines are subject to safety and security standards established by the NEB
or applicable provincial regulators. The NEB’s security standard includes criteria for
establishing a security management programme to ensure security threats and associated
risks are identified and managed and proper procedures are in place to minimise the
effects of any security breaches.
Electricity infrastructure in Canada is subject to standards established by the
North American Electric Reliability Corporation (‘NERC’) and various regional
reliability organisations (‘RROs’), which have established specific standards for
protecting the security of the bulk electric system. NERC and RRO standards are often
made enforceable through memorandums of agreement signed by provincial regulators.
The federal Export and Import Permits Act contains restrictions on the transfer
of technology outside of Canada. Generally, the Act restricts the export of technology
that is required for the development, production, or use of certain groups of products
identified on the Export Control List. The most notable items on the list for the energy
sector are nuclear dual-use goods and technology.
IV
ENERGY MARKETS
i Development of energy markets
In Ontario, wholesale and retail competition in the electricity market has been dampened
by government intervention in the form of price caps, subsidies, rate-regulated baseload
generation and other policies. A merchant generation market has not developed in Ontario
and most new generation supply is procured by a government agency, the Ontario Power
Authority (OPA), under long-term power purchase agreements. While all generation
is, in fact, offered and scheduled through a real-time spot market administered by the
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Independent Electricity System Operator (‘IESO’), most customers are largely insulated
from the spot price through the aforementioned regulatory measures. Currently, there
are initiatives underway to enhance price fidelity and competition in the IESO market.
Alberta has fully functioning competitive wholesale and retail markets. The AESO
contracts with transmission facility owners to provide generators access to the electric
grid. All wholesale power must be sold through the power pool, which is operated by the
AESO, subject to a few exceptions such as ‘behind-the-fence’ generation or sales under
direct sales contracts or forward contracts. The AESO dispatches power through the
power pool based on relative economic merit. It is also important to note, however, that
much of the electricity traded in Alberta is not priced at the hourly pool price, rather
the price is set in a direct sales contracts or forward contracts pursuant to the exception
noted above. For example, forwards market trading organisations, such as the Alberta
Watt Exchange, provides wholesale power purchasers with the option to buy quantities
of power (one hour out, one day out, one month out, one quarter out and one year out).
Electricity retailers, in turn, buy large blocks of energy and then repackage it into offers
to end-use consumers, whether that is through the regulated rate or contracts. Alberta
has an ‘energy-only’ market, where generators are paid for their electricity output on an
hourly basis and do not receive any other out-of-market compensation, such as capacity
payments.
In other provinces that do not have competitive power markets there are some
government procurement opportunities for independent power producers. There is
also substantial trade between provincial utilities (e.g., Hydro-Québec, BC Hydro) and
neighbouring US markets. In particular, British Columbia, Manitoba and Quebec – all
of which have abundant hydro resources – export substantial amounts of power to the
United States. These exports have in the past produced outsized profits; however, the
advent of plentiful shale gas has recently depressed electricity prices in the United States
making exports to the US less lucrative.
Canada has a well-developed national natural gas market. Traditionally, gas has
been shipped from western Canadian producers to customers in eastern Canada and the
US northeast (although as noted above the recent proliferation of shale gas in North
America is fundamentally altering this). The Canadian and US natural gas markets
operate as one large integrated market. Canadian gas production is connected to the
North American gas market through a network of thousands of kilometres of pipelines
that allows buyers to purchase and transport natural gas from a number of supply sources
across the continent.
The natural gas price has three components: the cost of the natural gas itself
(known as the commodity cost), the pipeline transportation cost and the distribution
cost. Generally, the transportation and distribution costs are regulated by government
agencies and tend to change moderately over time. The commodity cost makes up most of
the final cost to consumers and will change in response to supply and demand conditions
and can be much more volatile. The Henry Hub, an intersection of numerous pipelines
in Louisiana, is the pricing point for natural gas traded on the New York Mercantile
Exchange (NYMEX). As such, many gas market transactions in North America are
based on the pricing at the Henry Hub. The AECO-C hub in south-east Alberta is the
main Canadian pricing point. The price of gas traded at these hubs is publicly available
and establishes a commodity cost of natural gas. Natural gas can be traded for physical
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delivery same day, or at some point in the future. A price set today for delivery at some
later date is referred to as a ‘future’ price. Spot and future prices are set through the
interaction of supply and demand through trading platforms such as the Natural Gas
Exchange in Alberta or the New York Mercantile Exchange in the United States.
Canada is a participant in the global oil market in which buyers and sellers trade
volumes, mostly on the basis of short-term contracts. It is this interaction that sets the
world price of oil. The Canadian and US markets for oil are fully integrated. Canadian
crude oil production is connected to the North American oil market through a network
of pipelines, tankers, rail and trucks. Although Canada is the sixth-largest producer in
the world, it produces only about 4 per cent of total daily production, so it does not have
a major influence on the world price of oil. Currently, Canada exports two-thirds of the
oil it produces each day, but also imports half of the oil it needs on a daily basis. Oil is
produced and exported from Western Canada and Newfoundland, while the refining
industry in Atlantic Canada, Quebec and part of Ontario relies upon imported crude oil
for feedstocks. Close to 100 per cent of Canadian crude oil is shipped to the United States,
to which Canada is the largest exporter of crude oil. Canada’s two major benchmarks
for crude oil are the Western Canada Select and Edmonton Par. As the United States is
Canada’s main export market, typically Canadian crude oil is priced relative to the crude
oil benchmark West Texas Intermediate, at Cushing, Oklahoma. Crude oil, like natural
gas, is bought and sold through a variety of contract types, including ‘spot’ transactions.
As noted above, there is currently a disparity between the price paid for Canadian oil
production and the world price, such that Canadian oil production is increasingly
looking for markets outside of the United States.
ii Energy market rules and regulation
Power and gas markets are for the most part separately regulated, and power is much
more heavily regulated. In Ontario and Alberta, there are market rules administered by
the respective independent system operators that govern and regulate the wholesale spot
market and related markets. These address, among other things, registration requirements,
reliability standards, prudential obligations, bid or offer protocols, dispatch, settlement,
compliance, penalties and dispute resolution. Retail markets are governed by various
consumer protection legislation or regulations and energy board rules and codes. These
typically impose more onerous requirements on sales to residential or other small-volume
consumers.
With regards to the gas market, wholesale trading is not governed by any pricing
regulations or rules in Canada. In the case of the retail gas market, like electricity, it is
also governed by various consumer protection statutes, regulations and energy board
codes and rules.
Some provinces in Canada have commodity futures legislation that regulates
trading and advising in commodity futures contracts and commodity futures options.
Moreover, in other provinces the definition of ‘security’ in securities legislation includes
over-the-counter derivative transactions (i.e., swap contracts) or physical transactions
(including to make or take future delivery of natural gas). As a result, these types of
financial transactions and physical transactions are governed by dealer registration and
prospectus filing requirements unless the transaction fits within certain exemptions. A
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number of provinces (including Alberta and British Columbia) have blanket orders that
address this issue by exempting such transactions from filing and registration requirements.
It is important to note that in Canada there is no national securities law and no national
securities regulator. Rather, securities law and regulation is the responsibility of the
provincial and territorial governments; however, many substantive aspects of securities
regulation are harmonised through the use of ‘national instruments’ or ‘national policies’,
which are adopted by each of the provincial and territorial regulators.
iii Contracts for sale of energy
In Ontario and Alberta, wholesale and retail customers may contract to purchase
electricity. In Ontario, residential and low-volume consumers may purchase from
competitive retailers or pay a default price passed through by their local distribution
company; this default price is periodically ‘smoothed’ by the OEB to reduce volatility. As
a result of rate-regulation of most baseload generation, various government subsidies and
price smoothing, the retail market for residential and low-volume consumers has been
significantly dampened. There is a more robust market for commercial and industrial
customers.
In Alberta, consumers are free to purchase their electricity from any licenced
retailer. Neither wholesale nor retail electricity prices are regulated, making Alberta
the only province with fully competitive wholesale or retail markets. Small-volume
consumers who do not wish to purchase electricity from a competitive licensed
retailer are eligible for a regulated rate available to eligible consumers until 30 April
2013. Owners of distribution systems must provide a regulated rate, either directly or
indirectly, by appointing a regulated rate provider. The AUC regulates the rates charged
by the regulated providers. As previously noted, much of the electricity traded in Alberta
is not priced at the hourly pool price; rather the price is set in a direct sales contracts or
forward contracts. These direct sales contracts and forward contracts must be undertaken
in accordance with rules set by the AESO.
In Canada, wholesale and retail customers may contract to purchase natural gas.
Depending on the province, the rate a customer pays for natural gas may be a regulated
rate or a contracted rate. Regulated rates are set by provincial regulators whereas the
provincial regulators have no jurisdiction over competitive contracts.
iv Market developments
A fundamental change that is being considered for Ontario’s wholesale electricity market
is to make transmission-connected renewable resources (particularly wind) dispatchable;
at present, renewable resources self-schedule and get paid whenever they are generating.
Due to the unprecedented increase in renewable resources (both transmission and
distribution-connected) Ontario has been experiencing surplus conditions during
non‐peak periods that have required it to dispatch off nuclear units in favour of wind
and other non-dispatchable renewable resources. The proposed changes are contentious
and may have a significant impact on wind generators whose contracts pay them only
when generating.
As noted above, western Canada is experiencing a number of new developments
that threaten to fundamentally change its oil and gas industry. Conventional oil and
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gas is increasingly being displaced by significant new investments being made to
develop the oil sands and shale gas reserves. Foreign investment in these projects is
rapidly accelerating through the proliferation of large joint ventures, financings and
acquisitions. This investment is fuelling rapid development of projects and of related
infrastructure. New pipeline proposals, such as Keystone XL and Northern Gateway and
the development of new facilities, such as LNG facilities near Kitimat, British Columbia,
promise access to new markets in Asia; if these come to fruition, they will significantly
alter the relationship between Canadian producers and markets in the United States.
These projects are likely to encounter regulatory challenges given their scale and the
issues they create with respect to the rights of First Nations, environmental impacts of
new oil pipelines, hydraulic fracturing and horizontal drilling and ‘dirty oil’. Initiatives
are underway to streamline Canada’s environmental review process and to address the
potential for regulatory log-jams; however, it remains uncertain how successful these
initiatives will be.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Several Canadian provinces have introduced policy initiatives to spur renewable
development in recent years. These policies include renewable energy funds, renewable
portfolio standards, renewable procurements and feed-in-tariff programmes.
Ontario’s green energy policies stand out as the most ambitious in Canada.
The Ontario government has mandated dramatic increase in renewable resources.
To meet this goal, the provincial government introduced legislation to dramatically
increase the contribution of renewable and conservation resources to Ontario’s supply
mix to encourage ‘green investment’ and ‘green jobs’ and to address climate change.
The centrepiece of the legislation is a feed-in tariff (FIT) programme, which provides
standard-offer prices and contracts for renewable generation, including wind, solar and
biomass. As part of promoting the ‘green economy’ objectives, the programme includes
domestic content requirements aimed at inducing wind turbine, solar panel and other
component manufacturers to locate in Ontario. The programme was launched in
late 2009 and promises to assist in meeting the government’s goal of 10,700MW of
non‐hydro renewable generation by 2015.
Other Canadian provinces have introduced more limited green energy initiatives.
Notably, Nova Scotia introduced a renewable portfolio standard to source 25 per cent of
its electricity from renewable sources by 2015 and is currently introducing a competitive
procurement to purchase approximately 300MW of renewable energy from independent
power producers. Similar standards also exist in New Brunswick and Prince Edward
Island. Quebec, despite significant untapped hydro resources, has mandated that 10 per
cent of its generation should be sourced from wind. It is expected that Quebec will issue
a call for further tenders for up to 700MW of wind in 2012 or 2013. Saskatchewan has
set up the ‘Go Green Fund,’ which will invest in results-based projects that contribute to
the reduction or avoidance of greenhouse gas emissions. Also, the Manitoba government
released ‘Green and Growing’, which provides a goal of developing 1,000MW of wind
power in Manitoba over the next decade.
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ii
Energy efficiency and conservation
Canada
At the federal level, the government has established an Office of Energy Efficiency (‘the
OEE’), which offers a number of grants and incentives to encourage energy efficiency.
The OEE’s initiatives have included efficiency standards, home retrofitting, and the
labelling of consumer products.
There are also various efficiency and conservation initiatives at the provincial
level. In Ontario, the provincial government has created a Conservation Fund to fund
electricity conservation initiatives. The Conservation Fund supports a wide variety of
electricity conservation projects, including programmes that allow electricity users to
take advantage of commercially available energy-saving measures and incentives.
iii Technological developments
Ontario has established a Smart Grid Forum that is composed of members of the utility
sector, industry associations, public agencies and universities. The purpose of the forum
is to make recommendations that focus on removing barriers to smart grid development
in the province.
VI
THE YEAR IN REVIEW
A pressing issue in Canada is facilitating the delivery of Canada’s abundant energy
resources to the rest of the world. This is exemplified by the controversy over the proposed
Keystone XL pipeline in the United States, which would deliver crude oil from the Alberta
oil sands to the refineries along the Gulf Coast. In October 2011, the NEB granted a 20-
year licence to export 10 million tonnes of LNG per year from British Columbia, and a
new C$5 billion export terminal in Kitimat is expected to begin shipping LNG to Asia
by 2015. Meanwhile, Royal Dutch Shell plc purchased a marine terminal near Kitimat
with a view to exporting even larger quantities of LNG with its Korean and Japanese
partners. Various proposals have been tendered to increase crude oil transport capacity
to the west coast of Canada, including projects by Enbridge, Kinder Morgan, Canadian
National Railway Co and Canadian Pacific Railway Ltd. In March 2012, the Canadian
government announced measures to streamline the regulatory process for these projects.
Continued discoveries and development of unconventional gas resources in North
America have the potential to dramatically change the continent’s energy landscape
in ways that could not have been predicted a few years ago. Among other things, the
potential for low cost gas-fired electricity generation has brought into question the
wisdom of Hydro-Québec’s current ‘big hydro’ projects and Ontario’s plans to refurbish
and expand its nuclear generating fleet; however, environmental questions about shale
gas extraction still linger, and Canadian jurisdictions are beginning to grapple with the
need to set new guidelines for practices such as hydrofracking.
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Chapter 6
Colombia
Patricia Arrázola-Bustillo and Fabio Ardila 1
I
OVERVIEW
Under the Colombian Constitution of 1991, the government is responsible for ensuring
the provision of public utility services. In order to enable the government to fulfil these
obligations, the Constitution grants the government the powers to monitor and regulate
public utility companies to ensure the continued availability of such services.
Prior to 1991, the Colombian government either provided public utility services
directly through specialist providers or granted concessions to private parties to provide
such services. Since 1991, the government has adopted a strategy designed to restructure
the power sector by implementing various programmes that seek to reduce administrative
inefficiency in electric enterprises, to establish a rational tariff structure that will allow
energy companies to recover the true economic cost of electric services and to establish
opportunities for the participation of private entities. In fact, the constitution allowed
private parties to provide public utility services, although the government retained
ultimate responsibility for the efficiency and availability of such services.
In 1994, significant reforms were undertaken to the public utilities industry. These
reforms, contained in Law 142 of 1994 (‘Law 142’) and Law 143 of 1994 (‘Law 143’)
were the result of constitutional amendments made in 1991, and created the basic legal
framework that currently governs the electricity sector in Colombia. The most significant
reforms included the opening up of the electricity industry to private sector participation,
the functional segregation of the electricity sector into four distinct activities, namely
generation, transmission, distribution and commercialisation, the creation of an open
and competitive wholesale electricity market (‘the MEM’).
As previously mentioned, the most important legislation regulating this sector are
Law 142, which contains the legal framework for public utilities and Law 143, which
regulates the generation, transmission, distribution and sale of power. Other relevant
1 Patricia Arrázola-Bustillo is a partner and Fabio Ardila is an associate at Gómez-Pinzón Zuleta.
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regulations include CREG Resolution 024 of 1995 issued by the Energy and Gas
Regulation Commission (‘CREG’), which regulates the MEM, while resolution CREG
025 of 1995 regulates the national transmission system expansion plan and resolution
CREG Resolution 071 of 2006, as amended and clarified, regulates the reliability charge
that power generators receive for the availability of their energy generation assets and
back-up energy generation capacity in order to guarantee an energy supply to end
users under emergency conditions. On the other hand, CREG Resolution 128 of 1996
provides certain rules for vertical and horizontal integration of business within the
energy market. Finally, it is worth mentioning that Law 99 of 1993 provides the general
environmental legal framework.
II
REGULATION
i The regulators
Although, strictly speaking, the CREG is the sole entity that is defined as a regulator in the
energy sector, there are other entities with roles in the industry. The constitutional duties
and responsibilities of the Colombian government with respect to the electricity sector
are generally carried out through several governmental entities, including the following.
The Ministry of Mines and Energy (‘the MME’) is responsible for the overall
policymaking and supervision of the electricity sector. It regulates generation,
transmission, trading, interconnection and distribution, and approves generation and
transmission programmes. Direct supervisory authority over the electricity sector is
entrusted to a number of agencies under its control, including the CREG and UPME,
which is a special administrative unit of the MME responsible for developing and
updating the national energy plan and the national reference expansion plans. UPME is
also responsible for forecasting the overall electricity requirements of Colombia, planning
and developing ways and means to satisfy such electricity requirements (including the
development of alternative sources of energy) and establishing programmes to preserve
and optimise the use of energy. All electricity transmission companies are required to
prepare and submit information to UPME upon UPME’s request.
The Superintendency of Domiciliary Public Utilities (‘the SSPD’) is a governmental
agency created pursuant to the Constitution, which possesses supervisory authority over
all public services companies. The SSPD monitors the quality and efficiency of all public
services companies, but does not issue regulations regarding their businesses. The SSPD
can also take over public services companies when the rendering of the service or viability
of such companies is at risk. The SSPD may impose sanctions on electricity companies
for non‐payment and violations of the code of operations applicable to the electricity
industry, which establishes the principles, criteria and procedures for the planning,
coordination and operation of the National Interconnection System (‘the NIS’) and for
non‐compliance with any of the resolutions of the CREG or the UPME. Penalties may
include monetary fines, removal of officers or administrative takeover.
The National Operation Council (‘CNO’) is a consultative entity composed of:
a one representative of each generation company accounting for more than 5 per
cent of the installed capacity of the NIS;
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b
c
d
e
f
two representatives appointed by state-owned generation companies accounting
for between 1 per cent and 5 per cent of the installed capacity of the NIS;
one representative appointed by transmission companies (which representative
has limited voting rights);
one representative appointed by all remaining generation companies;
the director of the National Dispatch Centre (‘CND’), who does not have voting
rights; and
two representatives appointed by distribution companies that do not engage
primarily in generation activities.
The CNO is responsible for establishing technical standards to facilitate the efficient
integration and operation of the NIS.
The Commercialisation Advisory Committee (‘CAC’) is an advisory entity
created by regulation, which assists the CREG with the commercial aspects of the MEM.
It is composed of four representatives of companies that develop both the activities of
generation and commercialisation, four representatives of the companies that develop
both the activities of distribution and commercialisation, four representatives of
commercialisation companies, and a representative of the Commercial Exchange System
Administrator (‘ASIC’), without voting rights.
The Superintendence of Industry and Commerce (‘SIC’) investigates, corrects and
sanctions restrictive commercial competitive practices. Likewise, the SIC is the competent
Colombian antitrust authority. The SIC also oversees mergers of companies operating in
the same productive activities to prevent the concentration or monopolisation of certain
industries.
XM, an affiliate of Grupo Empresarial ISA, is responsible for planning and
coordinating the NIS’s operations, managing the commercial exchanges in the MEM
and billing for use of the NIS. ASIC is a subdivision of XM, which is responsible for the
registration of contracts and the settlement and billing of all transactions that take place
on the wholesale energy market. The CND is also a subdivision of XM and is responsible
for the planning, supervision and control of the operations of the NIS.
Finally, alongside the aforementioned entities, which have an important role in the
energy sector, there is the regulator. The CREG is a special independent administrative
body created in 1994 and whose main purpose is to regulate and promote competition
between the different areas of the energy business in such a way that an efficient and highquality
service can be provided. Its membership consists of the MME, the Minister of
Finance, the Director of the Department of National Planning and five experts appointed
by the President for a four-year term. Resolutions of the CREG require the approval of
a majority of the CREG’s members, which gives the expert appointees effective control
over the CREG’s actions. The following functions have been assigned to the CREG by
Law 142 and Law 143:
a promoting market competition;
b establishing the conditions for the gradual deregulation of the sector towards an
open and competitive market;
c approving interconnection and usage charges for the transmission and distribution
of electricity;
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d
e
f
g
establishing the methodology for calculating usage charges for the regulated
market;
defining the regulated and unregulated end-user markets;
establishing the regulations for the planning and coordination of the operation of
the national transmission system; and
establishing technical criteria relating to the quality, reliability and security of
supply.
ii Regulated activities
As a general rule, the generation, transmission, distribution and commercialisation are
all activities that are subject to the CREG’s resolutions. In order to undertake any of
these activities there is no need of a specific licence; however, depending on the specific
situation these activities may require environmental licences and urban planning
permissions.
iii Ownership and market access restrictions
Pursuant to applicable regulations, the electricity sector is largely segregated. In order
to achieve efficiency in the provision of electricity services and encourage privatesector
investment, Law 142 and Law 143 segregated the electricity industry into
the four mentioned service functions: generation, transmission, distribution and
commercialisation. Therefore, pursuant to Article 74 of Law 143, the vertical integration
of utilities incorporated after the enactment of such Law is prohibited.
Likewise, according to Article 1 of CREG Resolution 095 of 1994, aiming to
keep the activities referred to in Article 74 of Law 143 fully separated, neither is the
vertical integration of utilities incorporated before the enactment of Law 143 of 1994
with utilities incorporated after such enactment permitted.
Where electricity companies were integrated prior to the enactment of Law
142, they are allowed to continue engaging in all of the functions in which they were
previously engaged on condition that they maintain separate accounting records for each
business activity.
On the other hand, companies incorporated after Law 142 and Law 143 can
simultaneously operate activities considered as complementary, such as generation and
commercialisation, or distribution and commercialisation; however, according to such
laws, companies cannot undertake generation and distribution activities at the same
time, and transmission companies cannot operate in any other activities.
There are others restrictions established by the CREG that are worth mentioning;
for example, there are regulations establishing certain other ownership and market share
restrictions such as:
a limits on the ownership interest that an electricity generation company may take
in an electricity distribution company; and
b pursuant to CREG Resolution 127 of 1996, no electricity generation company
may directly own more than 25 per cent of the capital of a distribution company.
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iv Transfers of control and assignments
Law 142 states that companies that render public services must avoid unjustified
privileges and discriminatory acts, as well as abstaining from any act that has the capacity,
purpose or effect of generating unfair trade or restricting competition in any way, or
abusing their dominant position. Similarly, those companies are subject to the special
unfair competition regime foreseen in Colombian law.
Therefore, in the event that any company does not comply with its obligations
regarding promotion of competition, the SSPD may impose penalties and can even take
over the business. Also, several resolutions issued by CREG have established additional
norms regarding competition and promotion in the electric sector. Specifically, the
regulation states that the SIC is the competent authority when dealing with company
integrations in the energy sector. According to the regulations, Law 1340 of 2009, the
SIC can object to an integration when it results in undue competition restrictions and
when they are used to obtain a dominant position in the market.
As previously noted, CREG regulations additionally establish some rules that
must be taken into account, such as the following:
a no electricity generator may have a participation in an electricity distribution
company exceeding 25 per cent of the distribution company’s capital (however,
this ownership restriction does not apply to affiliates or subsidiaries of electricity
generation companies);
b pursuant to CREG Resolution 60 of 2007, no company can have market
participation above 25 per cent in the generation activity; and
c according to CREG Resolution 24 of 2009, no company can, directly or indirectly,
have a greater participation than 25 per cent in the commercialisation activity.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
As previously mentioned in Section II.iii, supra, the vertical integration of utilities
incorporated before the enactment of Law 143 with utilities incorporated after such
enactment is not permitted.
ii Transmission/transportation and distribution access
Electricity transmission is defined by applicable CREG regulations as the transportation
of electricity at a tension level equal to or greater than 220kv. In Colombia, electricity
transmission is regulated independently from other components of the electricity sector,
and has the unique characteristics of a natural monopoly. The National Transmission
System (‘NTS’) is an interconnected system for electricity transmission comprising
an array of electricity transmission lines and corresponding interconnection modules,
operating at 220kv or above.
The vast majority of generating stations, grid supply points for electricity
transmission and end-users are directly or indirectly connected by the NTS. The NTS
enables the operation of generating stations to be coordinated, which reduces the amount
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of backup generating capacity needed for plant maintenance and the amount of reserve
needed on a daily basis.
The NTS is made up of two subsystems, one on the Atlantic coast and one in
the central part of Colombia, which are interconnected by 500kv lines. The NTS links
Colombia’s 43 local and regional electricity distribution and transmission networks into
a single interconnected network. Approximately 92 per cent of the electricity consumed
in Colombia is transmitted over the NTS. The remainder is mainly generated and
consumed locally in Colombia’s sparsely populated south-eastern region. The Colombian
power grid is also interconnected at three points with the Venezuelan power grid and at
two points with the Ecuadorian power grid.
It is important to note that the NTS operates under open-access principles. In this
sense, all market participants in the electricity industry are entitled to access the NTS
to the extent that they comply with legal, technical and certain payment obligations,
including the payment of interconnection and usage charges. It is relevant to point out
that electricity transmission companies cannot engage in the purchase or sale of electricity.
Also, these companies have no decision-making powers in respect of the expansion of
the NTS or in respect of the NTS’s utilisation parameters. These decisions are made by
the MME following studies and recommendations made by the UPME. The revenue of
electricity transmission companies is channelled towards recouping their investments in
the NTS, as well as their operation and maintenance costs.
iii Rates
The CREG determines the formula with which to calculate the remuneration of energy
distributors via resolutions issued by said entity. This remuneration is divided into two
components: connection and usage charges. Usage charges for the distribution network
are set in such a way that end users must pay only the traders that supply them with a
single final charge. Usage charges are calculated with reference to a nominal charge ($
per kWh).
Even though there is no applicable regulation that obliges CREG to update the
formula, this entity may, in any case, revise the charge and at any point in time issue new
regulations in compliance with the applicable law.
IV
ENERGY MARKETS
i Development of energy markets
The energy is sold through the MEM, which is based on a competitive market model
and operates under open-access principles. The government participates in this market
through an institutional structure that is responsible for setting out policies and
regulations, as well as for exercising surveillance and control powers in respect of market
participants. The MEM relies for its effective operation on a central agency known as
the ASIC. This agency is in charge of the registration of contracts and the settlement and
billing of all the transactions that take place at the MEM.
The MEM is formed by various systems for the exchange of information
between electricity generation and commercialisation companies operating in the NIS.
These systems are designed to enable market participants to make long-term electricity
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transactions. All of the electricity supply offered by generation companies connected to
the NIS and all of the electricity requirements of end users, whose demand is represented
by commercialisation companies, is traded at the MEM. The NIS is formed by generation
plants, the NTS, the regional and inter-regional transmission lines, the distribution lines
and the electrical loading points of the users.
A substantial majority of the electricity generated in Colombia is initially
purchased on a wholesale basis through the MEM. The demand is covered through
electricity sales contracts between electricity generators and traders. In the daily process,
the participating agents converge on the spot market, adjusting their hourly transactions.
XM, through CND, conducts the planning, supervision and control of the operation
of the resources of the NIS. Also, the Liquidator and Administrator of Accounts is
responsible for liquidating the transactions, and XM manages the ASIC and is in charge
of the settlement and administration of the charges for the use of NTS networks in the
interconnected system.
The designated participants of the MEM are generation and commercialisation
companies. Generation companies are required to participate in the MEM with all of
their generation plants or units connected to the NIS with capacities equivalent to or
exceeding 20MW. Generation companies declare their energy availability and the price
at which they are willing to sell it. This electricity is centrally dispatched by the CND.
All commercialisation companies that deal with end-users connected to the NIS
are required to conduct their electricity transactions through the MEM. Electricity
transactions in the MEM are carried out under the following ways: the energy spot
market, bilateral contracts and firm energy. All generation companies in the MEM can
freely enter into any or all of these transactions.
ii Energy market rules and regulation
As we mentioned, Colombian law provides for open access to the NTS, and assures
any trader the right to connect its assets and network to and use the NTS, through the
payment of interconnection and usage charges payable to transmission companies by
users and liquidated by XM on a monthly basis. Access to the electricity exchange is
provided to electricity generators and electricity traders through the facilities of XM. XM
conducts the planning, supervision and control of the operation of the resources of the
NTS, and the administration of the NIS.
In order to have access to the MEM and execute commercial transactions
in the electricity exchange, market participants must enter into a contract with XM,
as administrator of the NIS and settler for the charges for the use of the NTS. The
contracts through which such transactions are executed have the features of mandate
agreements. Pursuant to the agreements, market participants authorise XM to represent
such participants with respect to the execution of transactions in the electricity exchange
and allow XM to collect, settle and distribute revenues received from market participants
in consideration for the use of the NTS and for the spot transactions entered into on the
electricity exchange.
Pursuant to the authority granted under the agreements, XM, as the SIC
administrator, records all the hedging contracts entered into by electricity generators
and traders, analyses dispatch on an hourly basis and calculates the amounts owed to or
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by generators and traders under the contracts and for energy exchange spot transactions.
XM only bills and collects the amounts owed with respect of transactions executed on the
electricity exchange. It nets out the amounts owed by electricity generators and traders
participating in transactions executed on the electricity exchange on an hourly, daily and
monthly basis and bills the generators and traders monthly.
Unlike other MEM market participants, electricity transmission companies do
not enter into any agreements with other market participants. The only agreements
entered into by electricity transmission companies are the agency agreements granted to
XM, which govern the terms on which XM performs billing, collection, payment and
settlement services on behalf of electricity transmission companies for the use of their
transmission assets.
iii Contracts for sale of energy
As announced before, electricity transactions in the MEM are undertaken in different
ways. The generation companies in the MEM can enter without restrictions into any or
all of these transactions.
Firm energy auctions
Firm energy auctions are aimed at allocating firm energy among electricity generators
and prospective investors willing to commit to construct new generation assets to provide
additional capacity to supply firm energy, and ensuring a firm energy among electricity
generators and investors is conducted through a dynamic auction mechanism. The
electricity demand of end users connected to the NIS is determined by a price/quantity
function established by the CREG in anticipation of the auction. Firm energy auctions
are conducted four years in advance of the date on which the firm energy obligation
is due. The price of firm energy obligations is established through descending clock
auctions.
The first firm energy auction took place in May 2008 and allocated firm energy
commitments from December 2012 to November 2013.
Bilateral contracts market
In the bilateral contracts market, generation and commercialisation companies sell and
purchase electricity under the terms of mutually and freely agreed contracts. The purpose
of these contracts is to reduce the exposure of both the supplier and the end-user of
electricity, to price volatility in the short-term market. The generation companies that
initially entered into the agreement, or other electricity generators determined under the
optimal dispatch mechanism, deliver the electricity committed under these contracts
through the energy spot market, which is explained later. There are no restrictions as
to the amounts of electricity to which a generation or commercialisation company can
commit under these agreements or the periods of time that may be covered therein. The
only requirement is for the contract to specify the quantity of electricity that will be used
on an hourly basis to enable ASIC to achieve the settlement required.
The purchase of electricity by commercialisation companies through bilateral
contracts to supply the demand of regulated users is subject to certain rules aimed at
ensuring fair competition among electricity generators. The purchase of electricity by
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commercialisation companies through bilateral contracts to supply the demand of
unregulated customers, however, is freely negotiated between the parties to the contract.
Energy spot market
The last modality is the transaction within the energy spot market. Under this system, the
transmission network is considered neutral, which implies that the electricity generator
sets its daily price offer and its hourly availability declaration without considering the
physical and technical restrictions of the transmission network. Electricity resources to
be dispatched at a particular time are selected based on the lowest price offers. This
mechanism is known as the optimal dispatch, and differs from the real dispatch because
in the latter the CND takes into account the restrictions that may affect the transmission
network. This price ranking system is intended to ensure that national demand is satisfied
by the lowest possible cost combination of available generating units.
The price offered by generation companies that participate in the MEM reflects
the variable costs of generation as well as opportunity costs. The price of the last resource
used to meet the total demand in each hour is the one that sets the price to be used to
pay all the infra-marginal resources in the same hour, and it is known as the spot price.
Electricity demand from commercialisation companies that is not covered by bilateral
contracts is settled at the spot price.
V
RENEWABLE ENERGY AND CONSERVATION
According to a study by the World Bank’s Energy Sector Management Assistance
Program (Annual Report 2011), Colombia has significant wind potential, which alone
could cover more than the country’s current total energy needs.
Notwithstanding the foregoing, the legal framework in this regard is still very
precarious and so the development of renewable energy is yet to start but may yet be a
great source of electricity generation. The main law related to renewable energy is Law
697 of 2001 by means of which the rational and efficient use of energy is promoted as
well as the use of alternative energy. Additionally, Decree 2755 of 2003 establishes tax
exemptions for wind generation plants. It was only in 2011, however, that the CREG
issued Resolution 092, which set out the methodology to determine the firm energy
from wind generation plants. It is important to bear in mind that this resolution is not
yet a definitive resolution and may still be subject to some modifications.
In conclusion, the renewable energy generation is still untapped in Colombia, but
with great potential due to the richness of natural resources within the country.
VI
THE YEAR IN REVIEW
In 2011, an auction took place where several projects were assigned. The goal of these
new projects is give more reliability to the system until 2016. Three of these projects are
for hydropower generation, while the remaining two are for thermal energy. Among the
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five projects assigned, four were led by the private sector 2 and the other by a state entity.
Moreover, one has a majority of foreign investment, mostly from a Chilean group.
In connection with new regulation, the CREG undertook several studies in order
to find other alternatives to warranty firm energy obligations. In this context, it issued
Resolution 106 of 2011 extended by Resolution 139 of 2011, by means of which it is
possible to ensure firm energy obligations with imported natural gas. Generators wishing
to use this new regulation must build and operate their own import facilities and have to
prove to the CREG that they have a supply agreement.
It is also worth mentioning that several market players have financed their future
investments in the international markets. For instance, EMGESA, EEB and TGI issued
debt in the international market. In all three cases, the issuance exceeded all expectations.
VII
CONCLUSIONS and OUTLOOK
Gradually, the Colombian electricity sector has been gaining weight and importance in
the current economic structure. This sector currently accounts for 2.03 per cent of total
GDP in Colombia. It also constitutes a significant source of employment generation,
exports and innovation.
The next challenge for the Colombian energy sector is to implement regional
interconnection. Currently, the NIS is physically connected with Ecuador and Venezuela.
Ecuador has integrated its regulatory parameters with Colombia in such a way that
international transactions are permitted; however, the goal is to interconnect more and
more countries. For this reason, recently Colombia entered into a $420 million agreement
with Panama, which would grant access to Central America’s regional electricity market.
Similar opportunities are present in other South American countries such as Chile, Peru
and Brazil.
Furthermore, according to the government, now Colombia has an installed
capacity of power generation of 14,000MW and consumes only 8,500MW leaving a
significant excess capacity that can go into neighbouring markets. With new hydroelectric
projects in progress, such as Hidroituango, Porce IV, the Quimbo and Hidrosogamoso,
the installed capacity in the country could increase by as much as 5,000MW.
2 Hidroeléctrico del Río Ambeima, Central Hidroeléctrica Carlos Lleras Restrepo and San
Miguel, Gecelca 32 and TermoTasajero II.
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Chapter 7
France
Fabrice Fages and Myria Saarinen 1
I
OVERVIEW
In France, the energy market has undergone a progressive liberalisation as a result of the
European plan to establish a unique energy market that would end national monopolies.
This has naturally led to an important legislative and regulatory change that was codified
by an order dated 9 May 2011, which created the legislative part of the Energy Code. 2
This Code sets out provisions relating to electricity, gas, renewable energy, hydropower,
oil and both heating and cooling networks.
This chapter will focus mainly on electricity and gas markets since they have been
the main energy markets affected by such changes. It should, however, be underlined that
the other sources of energy are also subject to specific regulation.
As a matter of history, after World War II, the French authorities decided, in order
to rebuild the infrastructures and the network, to grant a state monopoly to Electricité de
France (‘EDF’) and Gaz de France (‘GDF’, today ‘GDF Suez’) with regards respectively
to the production, transportation and distribution of electricity and gas. 3 This situation
remained substantially unchanged for half a century until France had to implement
into its national law two directives dated 1996 and 1998 adopted by the European
Commission in order to promote an effective and efficient internal energy market, open
to competition. These directives were progressively transposed into French law as of 2000 4
1 Fabrice Fages is a counsel and Myria Saarinen is a partner at Latham & Watkins AARPI. This
chapter was written with the contribution of Julie Ladousse, an associate at the firm.
2 Order No. 2011-504 of 9 May 2011.
3 Law No. 46-628 of 8 April 1946 concerning the nationalisation of electricity and gas, repealed
by the Law No. 2004-803 of 9 August 2004.
4 Law No. 2000-108 of 10 February 2000 concerning the modernisation and the development
of the electricity public service, transposing Directive 96/92/EC of 19 December 1996
concerning common rules for the internal market in electricity; Law No. 2003-8 of 3 January
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and initiated the beginning of the liberalisation, although initially only large industrial
consumers could benefit from this system.
Further opening of the energy market occurred several years later with the
transposition into French law of new directives dated 2003, which aimed to make such
opening available to all professional consumers by 1 July 2004, and to all consumers,
including residential or customers, by 1 July 2007. 5
Although significant progress had been made, the European Commission adopted
the Third Energy Package to further liberalise the energy market, which included two
new directives 6 replacing the former electricity and gas directives. These directives were
transposed into French law on 7 December 2010 by a new law commonly referred
to as ‘Law NOME’. 7 In addition, Law NOME led to the removal of obstacles of the
development of competition on the French electricity market. Greater price liberalisation
for industrial and residential customers has been achieved, by requiring EDF to sell a
substantial part of its existing nuclear facilities to alternative suppliers at a regulated
price (ARENH), from January 2011 to 2025, so as to allow alternative suppliers to fairly
compete with the historical supplier.
II
REGULATION
i The regulators
Compliance with the new energy market regulations is mainly controlled by the
Commission of Regulation of Energy (‘the CRE’), the sectoral regulator, which was
created by the Law dated 10 February 2000. 8 Its overall mission is to ‘contribute to
2003 concerning the electricity and gas markets and the public service of energy, transposing
Directive 98/30/EC of 22 June 1998 concerning common rules for the internal market in
natural gas.
5 Law No. 2004-803 of 9 August 2004 concerning the electricity and gas public service and
the electricity and gas companies, transposing (1) Directive 2003/54/EC of 26 June 2003
concerning common rules for the internal market in electricity and repealing Directive 96/92/
EC, and (2) Directive 2003/55/EC of 26 June 2003 concerning common rules for the internal
market in natural gas and repealing Directive 98/30/EC. Law No. 2005-781 of 13 July 2005
setting out the guidelines for energy policy regarding professionals and Law No. 2006-1537 of
7 December 2006 for individuals completed the transposition of these directives.
6 Directive 2009/72/EC of 13 July 2009 concerning common rules for the internal market
in electricity and repealing Directive 2003/54/EC; Directive 2009/73/EC of 13 July 2009
concerning common rules for the internal market in natural gas and repealing Directive
2003/55/EC.
7 Law No. 2010-1488 of 7 December 2010 establishing a new organisation of the electricity
market.
8 CRE is governed by three founding acts: Law No. 2000-108 of 10 February 2000, concerning
the modernisation and the development of the electricity public service; Law No. 2003-8 of 3
January 2003 concerning the gas and electricity market and the public service of energy; Law
No. 2010-1488 of 7 December 2010 establishing a new organisation of the electricity market.
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the proper operation of the electricity and natural gas markets, to the benefit of final
customers’.
The CRE is principally in charge of:
a powers of decision, approval or authorisation (system operators, contributions to
the public electricity sector, etc.);
b dispute settlement and sanctions relative to access to the electricity and gas
networks;
c powers of proposal (tariffs for the use of public electricity grids, contributions to
public electricity services, etc.);
d information and investigative powers with stakeholders;
e advisory powers (tariffs, regulated access to incumbent nuclear electricity, etc.);
and
f additional powers (processing of tenders for electricity generation, etc.).
The CoRDiS committee, which is an independent body of the CRE executes CRE
competencies with regard to sanctions and settles disputes related to the access and use
of public electricity grids and natural gas networks.
Further, an energy ombudsman has been put in place whose role is to provide
consumers with all necessary information concerning their rights, current legislation and
the means of dispute settlement available to them in the event of a dispute.
In addition, the French Competition Authority (‘the FCA’) has the power to
prevent and sanction anti-competitive practices in any economic sector, including
electricity and gas. It must inform the CRE when seised of any matter that would fall
under the CRE’s jurisdiction. The FCA must also notify the CRE of any abuse of a
dominant position or any anti-competitive practice in the gas or electricity sector. 9
ii Regulated activities
The energy market is composed of four main areas of activity: production (generation),
transmission, distribution and supply (commercialisation). Under the previous regime,
which was applicable until 2000, these four activities were carried out by EDF and GDF,
which self-regulated the monopoly.
There have now been greater strides towards liberalisation as production and
supply are open to competition. Transmission and distribution are still, however, public
service activities supervised by the CRE (see Section II, infra). In the regard, in order
to guarantee this public service mandate, a legal and financial separation between
such activities has taken place: 10 transmission is performed by GRT (Gas) and RTE
The legal framework applicable to the CRE is defined in Articles L131-1 to L135-16 of the
French Energy Code.
9 Article L134-16 of the French Energy Code.
10 Law No. 2004-803 of 9 August 2004 concerning the electricity and gas public service. Law No.
2010-1488 of 7 December 2010 on the new organisation of the electricity market.
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(Electricity), and distribution is performed by GRDF (Gas) and ERDF (Electricity) or
local distribution companies. 11
More generally, some activities require an administrative authorisation such as
the exploitation of electricity production facilities. This authorisation is delivered by
the Minister of Energy according to specific considerations such as security, energy
efficiency, technical and economic capacities of the applicant. 12 Similarly, gas exploration
also requires an administrative authorisation or a concession, which is granted further to
a public enquiry and a tender procedure. 13
iii Ownership and market access restrictions
Although the French Energy Code does not provide for any restriction or requirement
in relation to the acquisition of assets in the energy sector by foreign companies or
individuals, it clearly states that the French state must hold at least 70 per cent of the
capital and voting rights of EDF and 30 per cent of GDF Suez 14 (in order to protect the
French national interest, the state may benefit from specific shares within the capital of
GDF Suez 15 ).
iv Transfer of control and assignments
Any merger or any change in control over businesses in the energy sector, or any
acquisition of utility assets, must be notified and supervised by the FCA if the following
three cumulative conditions are met: 16
a worldwide aggregate turnover of all the parties to the concentration exceeds €150
million;
b turnover in France of each or at least two parties concerned exceeds €50 million;
and
c the transaction does not meet the EC Merger Regulation thresholds.
The examination process by the FCA is twofold. In stage I (which takes up to 40 working
days), the FCA has 25 working days to examine the transaction starting from the date
when a complete notification is received. When remedies are proposed to the FCA, this
period is extended by up to 15 working days. At the end of this period, the FCA can clear
the transaction, with or without remedies or proceed to an in-depth investigation. In the
absence of any decision, the transaction is tacitly cleared.
Stage II takes between 65 and 85 working days. If serious doubts remain as to the
competitive impact of the transaction, the FCA proceeds with an in-depth investigation.
During this stage, if the transaction relates to a regulated area, the FCA may request a
11 Local distribution companies are defined by Article L111-54 of the French Energy Code.
12 Article L311-5 of the French Energy Code.
13 Articles L131-1, L132-3 and L132-4 of the French Mining Code.
14 Articles L111-67 and L111-68 of the French Energy Code.
15 Article L111-69 of the French Energy Code and Article 10 of the Law No. 86-912 dated
6 August 1986.
16 Articles L430-1 and L430-2 of the French Commercial Code.
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non-binding opinion from the relevant regulator (e.g., the CRE). At the end of stage
II, the FCA can either clear the transaction with or without remedies or prohibit the
transaction.
The FCA’s authorisations for acquisitions may be subject to conditions. 17
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Vertical integration is the process in which different aspects of the market are controlled
by a common company or entity. Prior to the deregulation of the energy industry, French
energy companies were largely vertically integrated, which created potential conflicts of
interests and monopoly situations.
The European Commission issued Directives 2003/54/EC and 2003/55/EC
in order to principally ensure efficient and non-discriminatory network access, ensure
free choice of suppliers by consumers, and encourage investment. This legislation was
transposed into the French system by a law dated 9 August 2004, which provided
for a legal unbundling of regulated activities (distribution and transmission) from
non‐regulated activities (production and supply). After an inquiry launched in 2005
by the European Commission, however, serious shortcomings in the electricity and gas
markets were identified, including an inadequate current level of unbundling between
network and supply interests deemed to have negative effects on the market and
investment. 18 Consequently, under Directives 2009/72/EC and 2009/73/EC, priority
was given to achieve effective unbundling of network and supply activities.
As explained above, these directives were transposed into French law in order for
the transmission and distribution system operators to be legally and fully unbundled
companies. Accordingly, transmission and distribution system operators must be
equipped with all the necessary human, technical, physical and financial resources to
fulfil their obligations under French law and, in particular, assets that are necessary for
their activity must be owned by them. 19
17 See for example the decision of the FCA dated 7 February 2012: the FCA made its
authorization of the acquisition of Enerest by Electricité de Strasbourg conditional on a
number of commitments designed to resolve competitions concerns, such as the commitment
not to make offers for two energies that include at least one component at a regulated tariff.
This commitment, the effectiveness of which is to be guaranteed by separating the sales teams
responsible for electricity and gas at Electricité de Strasbourg, notably eliminates any risk of the
company using its business of supplying energy a regulated tariffs as a tactic to win customers
on the open market.
18 Final report from the Commission relating to the inquiry pursuant to Article 17 of Regulation
(EC) No 1/2003 into European gas and electricity sectors, dated 10 January 2007.
19 Articles L111-19 (transmission) and L111-59 (distribution) of the French Energy Code.
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ii
France
Transmission/transportation and distribution access
Non-discriminatory and fair access to transmission and distribution networks for gas and
electricity are at the core of the free market approach. 20 Any discrimination, prevention
of new participants from entering the market, and fair competition in favour of the
consumer, is subject to sanctions issued by the CoRDiS committee. 21
Among the measures guaranteeing such non-discriminatory and fair access, it
should be noted that any refusal to enter into an agreement must be justified and notified
to the applicant, as well as to the CRE, specifying that any refusal is justified by objective,
transparent and non-discriminatory reasons. 22
Furthermore, any transport or distribution system operator serving more than
100,000 clients must draw up a code of conduct in order to ensure compliance with the
non-discrimination principle. 23
Finally, the CRE must publish an annual report concerning compliance with the
code of conduct and a summary of its assessment of the independence of the transport
or distribution system operators. 24
iii Rates
Pursuant to Articles L341-2 and L452-1 of the Energy Code, access tariffs to networks
aim at guaranteeing transparent and non-discriminatory access to public networks. These
fees are calculated in a way that cover all costs supported by the system operators (costs
arising from their public service duties, the research and development needed to increase
the transmission capacity, and the grid connection).
The methodology used to establish access tariffs to the network is set up by
the CRE. In addition to fixing the rates the CRE grants appropriate incentives for
transmission and distribution system operators over both the short and long term in
order to increase efficiency, foster market integration and security of supply and support
related research activities. 25
iv Security and technology restrictions
Security of electricity and gas supply is an essential public service obligation. 26 The
Ministers of Energy and Economy must ensure the fulfilment of this public service mission
mainly by EDF, GDF, RTE, GRT, ERDF, GRDF and local distribution companies.
In case of serious energy shortage, the government may subject energy resources
to control and allocation. 27 In case of a serious energy market crisis, threat to the safety
or security of the networks and of people, the Minister of Energy may take protective
20 Articles L111-91 et seq. of the French Energy Code.
21 Articles L134-25 et seq. of the French Energy Code.
22 Articles L111-93 (for electricity) and L111-102 et seq.. (for gas) of the French Energy Code.
23 Article L111-61 of the French Energy Code.
24 Article L134-15 of the French Energy Code.
25 Articles L341-3 (electricity) and L452-2 (gas) of the French Energy Code.
26 Articles L121-1 (electricity) and L121-32 (gas) of the French Energy Code.
27 Article L143-1 of the French Energy Code.
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measures to grant or suspend licenses for the operation of power generating facilities .
In times of war or serious international tension, the government may regulate or even
suspend oil import or export completely. 28
IV
ENERGY MARKETS
i Development of energy markets
The sale of energy takes place within either the wholesale market or the retail market. The
wholesale market is the market in which electricity and gas are traded (bought and sold)
before delivery in the network to final customers (individuals or companies), whereas
the retail market concerns the final clients who may freely choose their suppliers (eligible
customers). 29
The participants of the wholesale market are:
a the producers who trade and sell their production,
b the suppliers who trade and supply gas or electricity before selling gas or electricity
to the final client, and
c brokers or traders who purchase gas or electricity for resale and thus favor market
liquidity.
As most of the activity in the wholesale gas market and wholesale electricity market takes
place over the counter, through direct transactions or through intermediaries (brokers
and trading platforms), 30 the opening of these markets to competition has led to the
emergence of organised markets, namely trading platforms (Epex Spot France and EEX
Power Derivatives France and Powernext).
ii Energy market rules and regulation
Even if the supply of energy is open to competition, it is still subject to certain
requirements and monitoring.
First, the sale of electricity or gas is subject to governmental approval. Indeed,
suppliers willing to purchase electricity or gas to sell them to consumers need an
administrative authorisation that is delivered subject to their technical, economic and
financial capacities, and according to their project’s compatibility with the security of
supply obligation. 31
Second, each transaction performed on the French market that would involve
the participation of a producer, broker or energy supplier, must be monitored by the
28 Article L143-7 of the French Energy Code.
29 Article L331-1 of the French Energy Code.
30 Commission de Régulation de l’Energie, Electricity and gas market report, fourth quarter of
2011.
31 Articles L333-1 (electricity), L443-1 and L443-2 (gas) of the French Energy Code.
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CRE, regardless of the trading method (two-way trades, with or without a broker or
transactions within organised markets). 32
Finally, free competition is limited with respect to pricing practices since, in
certain circumstances, ‘regulated tariffs’ may be chosen by buyers. Such ‘regulated tariffs’,
combined with the lack of access by alternative suppliers to the existing nuclear facilities,
enhanced the European Commission’s unhappiness, especially with the electricity retail
market and the dominant position exercised by EDF. For this purpose, Law NOME
provides that ‘regulated tariffs’ are to disappear after 2015 for customers having
contracted for more than 36kVA (‘yellow’ and ‘green’ tariffs); however, for customers
having contracted for less than 36kVA (‘blue’ tariffs), the ‘regulated tariff’ will remain
applicable. 33
Furthermore, all operators providing electricity to final consumers may benefit
from the access to historical nuclear energy at the regulated price, ARENH, only up to
the 100TWh to be allocated between the suppliers. The price of the ARENH is set at
€42/MWh for the coming months.
iii Contracts for sale of energy
The legal unbundling between the production and the distribution activities imposed by
the energy market creates several inconveniences for the consumer who, as a result, gets
an increasing number of contractors and the responsibilities of which are diminished.
In order to prevent this, the Law dated 7 December 2006, completed by the
Law NOME, created a new section in the French Consumer Code entitled ‘electricity
supply or natural gas contracts’ (Articles L121-86 to L121-94). These provisions apply
to contracts concluded by consumers and professionals for less than 36kVA (electricity)
or less than 30,000 kW (gas).
According to Article L121-92 of the Consumer Code, the energy supplier
‘must give the client an opportunity to sign a single contract dealing with both the
supply and the distribution of electricity or natural gas’. This contract, which should
at least last for one year, thus creates a tripartite relationship between the supplier, the
distributor and the consumer, even though the supplier often remains the consumer’s
main interlocutor.
The supplier must mention several specific provisions both in the offer and the
contract. Failure to do so is subject to sanctions. 34 The consumer can rescind the energy
supply contract at any time if it plans on changing supplier. Professionals are not entitled
to ask the consumer for any other costs than the ones incurred by the rescission, provided
that these costs were mentioned in the offer. 35
32 Article L131-3 of the French Energy Code and www.cre.fr/en/markets/wholesale-market/
introduction.
33 Articles L337-9 and L337-7 of the French Energy Code.
34 Articles R121-14 to R121-21 of the French Consummation Code.
35 Articles L121-89 of the French Consummation Code.
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iv
Market developments
France
Market developments have taken place in different areas, and in particular on the cost of
electricity with the Law NOME. Moreover, the renewal of hydraulic concessions have
recently been launched. 36 Finally, various reports were submitted at the beginning of
2012, aimed at clarifying what should be the investments to ensure the security of supply.
V
Renewable energy and conservation
i
Development of renewable energy
In July 2007, the French government launched the Grenelle Environment Forum, a
major national consultation that led to the emergence of priority targets in terms of
controlling energy consumption and promoting renewable energies. This forum led to
the enactment of two ‘Grenelle Laws’, respectively on 3 August 2009 (‘Grenelle I’) and
12 July 2010 (Grenelle II), 37 aiming at promoting environmental objectives such as,
the increase of the share of renewable energy to at least 23 per cent of final energy
consumption before 2020, in accordance with European Union Directive 2009/28/
EC. 38 These laws were codified in a separate section dedicated to renewable energy in
the Energy Code. 39
To enhance the development of renewable energies, public authorities can use
two economic instruments. 40 First, feed-in tariffs require the historical operator to buy
energy produced from renewable sources, for a regulated tariff over a long period, which
can be changed and is slightly higher than the market price. Second, calls for tender
can be used to determine ex ante the quantity of renewable energies benefiting from the
public support.
ii Energy efficiency and conservation
In order to achieve a 20 per cent increase in energy efficiency, in accordance with the
climate and energy package, 41 on 22 June 2011 the European Commission presented a
36 www.developpement-durable.gouv.fr/Les-concessions-hydroelectriques.html.
37 Law No. 2009-967 of 3 August 2009 relating to the implementation of the Grenelle
Environment Forum and Law No. 2010-788 of 12 July 2010 relating to national commitment
for environment.
38 Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on
the promotion of the use of energy from renewable sources and amending and subsequently
repealing Directives 2001/77/EC and 2003/30/EC.
39 Articles L211-1 to L261-1 of the French Energy Code.
40 www.cre.fr/operateurs/producteurs/appels-d-offres.
41 The climate and energy package was presented by the European Commission on January
2008. It suggested to implement the ‘20-20-20 targets’: (1) A reduction in EU greenhouse gas
emissions of at least 20 per cent below 1990 levels, (2) 20 per cent of EU energy consumption
to come from renewable resources, and (3) a 20 per cent reduction in primary energy use
compared with projected levels, to be achieved by improving energy efficiency.
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draft Directive that is currently being discussed at the Council of the European Union
and at the European Parliament. The Directive should come into force by the end of
2012 and be transposed by Member States by the end of 2013.
In France, energy efficiency is also a priority since Grenelle I sought to achieve
a rate of energy efficiency between 19.7 per cent and 21.4 per cent by 2020. Examples
of measures aimed at achieving this goal include certificates of energy savings and
sustainable development tax credit.
The French government claims a strong European framework in order to achieve
the ‘20 per cent target’ it will benefit france, and confirmed on 13 April 2012 its full
support of the European Commission’s proposed Directive.
iii Technological developments
The draft European bill on energy efficiency made public on 22 June 2011 includes
several provisions related to the development of smart grids, the aim of which is to reduce
bill by paying what was really consumed and by understanding how to consumption
patterns better. The development of smart grids is based on the idea that it improves
energy efficiency and better integrates renewable energy resources in the network.
The development of smart grids has also been decided in France. Indeed, a decree
dated 31 August 2010 provided that new connection points must be equipped with smart
grids from 1 January 2012 and provided for a test run or pilot for such equipment. 42
Based on the results of a pilot programme conducted in 2010 and 2011 by ERDF,
the largest French distribution system operator, the government plans to deploy 35
million smart grids to electricity customers throughout the country before 2020.
VI
The year in review
2011 and the beginning of 2012 were characterised by several developments in the
energy sector.
i Decrees following the publication of Law NOME
Law NOME provides that every operator providing electricity to final consumers must
have regulated access to historical nuclear energy (ARENH) produced by EDF nuclear
power stations. The Law has been followed by a range of decrees on calculation of the
ARENH tariff or prices such as :
a Decree n° 2011-466 of 28 April 2011 setting out the rules for regulated access to
historical nuclear energy (ARENH),
b Order of 28 April 2011 setting out the maximum volume of electricity to be
transferred by EDF,
c Order of 17 May 2011 relating to the calculation of the rights of access to
historical nuclear energy,
d Order of 17 May 2011 setting out the price of regulated access to historical
nuclear energy from 1st January 2012.
42 Articles 6 and 3 of the Decree No. 2010-1022 dated 31 August 2010.
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ii
France
Capacity mechanism in the electricity sector
Pursuant to Article L335-6 of the French Energy Code, 43 the government intends to create
by decree a market for capacity trading, planned as a way of encouraging investment in
extra production capacity by suppliers and saving energy during peak demand periods.
The FCA, which was asked for a notice on such decree and rendered it on 12 April 2012, 44
raises questions about the need to set up a market for capacity trading and considers that
less expensive solutions exist to control peak demand of electricity such as the increase
of the regulated tariffs. Furthermore, it warns that such a market could increase the costs
of alternative suppliers.
iii The cost of gas
On 1 October 2011, the government decided to freeze gas prices. This decision provoked
complaints from GDF Suez, which that claimed this would impede fair competition. The
case was brought before the French Supreme Court, which invalidated such decision. 45
Therefore, an increase of 4.4 per cent in the cost of gas from 1 January 2012 has been
decided by an Order dated 23 December 2011.
VII
Conclusions and outlook
Since 1 July 2007, all customers have been able to choose their gas and electricity
suppliers and the Law NOME has increased competition in the electricity market. A
fully free market as such still does not, however, exist. Several safeguards are in place,
such as regulated tariffs and ARENH, which are in part due to the fact that France
is strongly committed to energy public service and the preponderance of the French
nuclear power plants.
Moreover, market developments are a matter for debate, especially about the Law
NOME in the French presidential and legislative campaign. The French energy sector is
thus not immune from new substantial developments.
43 Article L335-6 provides that a decree shall specify the conditions of application for the
provisions related to security of electricity supply (L335-1 et seq..).
44 Notice No. 12-A-09 dated 12 April 2012 concerning a draft decree linked to the creation of a
market for capacity trading in the electricity sector.
45 Decision 28 November 2011, No. 353554 (Conseil d’Etat).
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Chapter 8
Germany
Dirk Uwer 1
I
OVERVIEW
As a consequence of the transposition of the European Third Energy Package (2009)
into German law, as well as the ‘energy turnaround’ 2 in the wake of the Fukushima
accident, the German energy markets have recently undergone some transitions and are
still facing significant challenges. On the one hand, structural changes occurred, as three
of the four major incumbent vertically integrated energy suppliers decided to sell their
electricity or gas transmission networks. On the other hand, new legislation was enacted
in order to facilitate further liberalisation of the energy markets and promote the energy
turnaround.
II
REGULATION
i The Regulators
The Energy Industry Act (‘the EnWG’) was implemented on 13 July 2005 as the main
statutory framework. As regards energy network-related activities, the EnWG replaced
negotiated third-party access by introducing regulated third-party access. The EnWG
has been supplemented by a number of ordinances, including the Ordinances on Tariffs
for Electricity and Gas Network Access (‘StromNEV’ and ‘GasNEV’), the Ordinance on
Incentive Regulation (‘the ARegV’) and the Ordinances on Access to the Electricity and
Gas Networks (‘StromNZV’ and ‘GasNZV’).
1 Dirk Uwer is a partner at Hengeler Mueller. The author would like to thank his colleagues Jörg
Meinzenbach, Daniel Zimmer and Carl-Christoph Werkmeister for their invaluable assistance.
2 The shift from a fossil fuel and nuclear-based to a sustainable energy supply based on renewable
energies.
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Germany
Since July 2005, the Federal Network Agency for Electricity, Gas,
Telecommunications, Post and Railway (‘the BNetzA’) has acted as the main regulator.
In addition, the regulatory authorities of the 16 German federal states are responsible
for the regulation of energy network operators with fewer than 100,000 customers
connected to their energy supply networks and whose networks do not extend beyond a
single federal state. The BNetzA has been entrusted with all tasks and powers that, under
the EnWG, have not been assigned to the state regulators.
The BNetzA’s regulatory tasks include, inter alia, ensuring non-discriminatory
network access, control of network access tariffs, monitoring potential anti-competitive
practices by network operators and the assessment of the network operators’ investment
activities. These regulatory powers have the primary objective to ensure safe and efficient
energy network operation and to provide necessary prerequisites for effective competition
on the upstream and downstream energy markets.
Another authority that acts as the regulator of the energy markets in a broader
sense is the Federal Cartel Office (‘the BKartA’). While the competition law regime
under the Act Against Restrictions of Competition (‘the GWB’) applies in principle to
all business sectors, it contains in Section 29 a special competence for the BKartA to
prohibit abusive pricing practices by dominant suppliers on the energy retail markets.
The BKartA has no jurisdiction over energy network-related activities that are solely
subject to measures imposed by the BNetzA or the responsible state authority. Both the
BNetzA and the BKartA are, however, under a duty of mutual cooperation in order to
seek a uniformity of measures with regard to the energy markets.
ii Regulated activities
In Germany, only the operation of energy transmission and distribution networks
is subject to a strict regulatory regime by the BNetzA and the competent regulatory
state authorities, respectively. This oversight extends to network access and network
connection obligations including network tariff regulation under the statutory regime
of incentive regulation. In addition, the operation of energy supply networks requires
certain licences and approvals:
The commencement of the operation of an energy supply network requires an
authorisation by the competent authority. The regulator must issue the approval within
six months after receipt of the complete application documents. Authorisation may only
be refused if the applicant lacks the necessary personal, technical and economic capability
and reliability in order to ensure the long-term operation of a network in accordance
with the provisions of the EnWG. Network operators that were already active when the
revised EnWG entered into force on 13 July 2005 do not require such authorisation
(grandfathering).
In accordance with Directives 2009/72/EC and 2009/73/EC, the operation
of a transmission network is now subject to certification by the BNetzA. To this end,
the BNetzA has published guidelines that substantiate the procedural and material
requirements. Accordingly, the certification process had to be initiated by the operator
or the owner of the transmission network by 3 March 2012 or can be initiated ex officio.
The BNetzA is currently in the process of preparing draft decisions (it has four months
to do so) and will forward these to the European Commission (‘the Commission’). The
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Germany
Commission may subsequently comment on the draft decision. Within two months
of receipt of the Commission’s opinion, the BNetzA must issue a final decision. The
BNetzA may grant the certification if the transmission system operator (‘TSO’) fulfils
the respective unbundling requirements of the EnWG (see Section III.i, infra). The
BNetzA may also issue the certification subject to certain terms and conditions.
If a TSO is (jointly) controlled by one or more persons from a country that is
not a member of the European Union or the European Economic Area, the TSO has
to undergo a special certification procedure. First, the application must be filed no
earlier than by 3 March 2013. Further, the German Federal Ministry of Economics
and Technology (‘the BMWi’) will have to issue an assessment of whether or not the
certification will endanger the security of energy supply in Germany and the EU.
Apart from licences and approvals, the regulatory authorities constantly monitor,
coordinate and partly approve investment decisions with a particular view to TSOs. In
this respect, TSOs are required to annually produce a ‘scenario framework’ as a basis
for an annual national network development plan. After public consultation with all
stakeholders involved, the BNetzA will approve the scenario framework in light of the
results of the public consultation. In addition, the TSOs have to apply for ‘investment
measures’ (previously called ‘investment budgets’) in the case of large restructuring or
expansion investments. The BNetzA grants respective approvals if the applicable statutory
requirements are fulfilled.
By way of contrast, similar regulatory restrictions do not apply to activities on
the generation and wholesale supply or energy retail markets. There are, however, certain
activities that do require special licences or other kinds of approvals. For example, the
construction of new power generation facilities requires a permit according to the Federal
Emission Control Act. More specifically, the construction and operation of a nuclear
power plant requires a special permit according to the Nuclear Energy Act.
iii Ownership and market access restrictions
In terms of unbundling options, the German legislator has completely transposed the
EU requirements in the EnWG. Thus, vertically integrated energy suppliers may opt
either for full ownership unbundling (‘OU’), an independent system operator (‘ISO’)
model or an independent transmission operator (‘ITO’) model. In practice, only the OU
and ITO models are relevant in Germany (see Section III.i, infra).
iv Transfers of control and assignments
When it comes to the transfer of control, the German legal framework does not provide
for special rules for the energy markets. However, depending on the market situation,
such change of control may be subject to the general merger control regime under the
GWB. The transfer of control will be approved by the BKartA as long as it does not create
or strengthen a dominant position in the relevant (energy) market. A recent example is
the approval of Gazprom’s increase of its minority shareholding in eastern Germany’s
largest gas supplier Verbundnetz Gas AG (VNG).
Furthermore, changes of control over a TSO trigger certain reporting duties. In
such a case, the TSO must notify the BNetzA of any proposed transactions, activities or
other circumstances that may require a reassessment of the aforementioned certification
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requirements (see Section II.ii, infra). The BNetzA shall then inform the Commission
and, as the case may be, the BMWi in order to reassess its validity. As a consequence, the
BNetzA may revoke, amend or impose conditions on the certification. Further, as regards
the certification in relation to third countries, the BMWi may revoke its assessments on
the security of energy supply in Germany and the EU.
Another specific regulatory reporting obligation exists in case of a (full or partial)
transfer of an energy supply network or the merger of different energy supply networks
under the network tariff regime of incentive regulation. In such scenario, the BNetzA
must be informed in order to transfer the original revenue caps for each energy supply
network to the acquiring network operator, or, in case of a merger, to combine the
different revenue caps into one single revenue cap.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Under the EnWG, full ownership unbundling is only required if the vertically integrated
energy supplier chooses not to set up an ISO or ITO model. Both the ISO and the ITO
models may only be implemented under the condition that the transmission network
belonged to a vertically integrated undertaking on 3 September 2009. However, as the
ITO model imposes the least structural requirements, it has in fact been chosen by all
vertically integrated energy suppliers in Germany; in contrast, the ISO model is of no
practical relevance in Germany. However, if the transmission network was acquired by
investors (e.g., infrastructure or pension funds) the option of full ownership unbundling
may also be appropriate.
In both the full ownership unbundling and the ITO model, the TSO remains as the
direct or indirect (through shareholding in another company) owner of the transmission
network assets; co-ownership is sufficient. In principle, the ownership requirement no
longer allows for the lease of infrastructure assets that German TSOs have historically
practised to a great extent. However, in its guidelines on the certification process the
BNetzA indicates that it will accept a lease model under certain circumstances if:
a the lessee exerts an influence over the leased assets that is comparable with the
position of the owner of such assets;
b part of the transmission network is leased from another TSO, which itself is
subject to unbundling requirements; and
c the leased objects do not constitute a significant part of the entire transmission
system, but rather play a subordinate role.
While under the ITO model the TSO may remain part of the vertically integrated
energy utility, the respective subsidiaries in charge of the transmission operation need
to be legally independent, operating under its own brand name and be organised under
a strictly autonomous management. Hence, vertically integrated energy suppliers are
obliged to ensure that the ITO is granted effective decision-making rights, independent
from the vertically integrated undertaking, with respect to assets necessary to operate,
maintain and develop the transmission network.
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Also in consideration of the statutory and regulatory measures, the structure of
both the gas and electricity markets with respect to the transmission of energy has changed
significantly during the past few years. Most importantly, within the past two years, three
of the four major incumbent vertically integrated energy suppliers in Germany have sold
or are in the process of selling (the majority stake of) their respective gas or electricity
TSO to third parties. This relates, in particular, to the following transactions:
a E.ON sold its entire electricity transmission network to TenneT, the Dutch
national electricity TSO, for an estimated €1.1 billion in 2010.
b Vattenfall sold its entire electricity transmission network to Elia, the Belgian
electricity TSO, and the Australian fund IFM for an estimated €810 million in
2010.
c RWE sold 75 per cent of the shares of its electricity transmission network operated
by Amprion to a consortium of buyers for an estimated €700 million in 2011.
d RWE sold its entire gas transmission network operated by Thyssengas to the
Macquarie infrastructure funds in 2011.
e E.ON is currently in the process of selling (part of) its gas transmission network
operator Open Grid Europe.
With the notable exception of EnBW, all of the four major incumbents have drastically
changed their business models. These companies now rather focus on the generation and
energy trading activities, and supply of energy, as these markets are not subject to the
strict regulatory regime of the EnWG.
ii Transmission/transportation and distribution access
Under the EnWG, operators of energy supply networks at all levels (transmission and
distribution) have to provide access to third parties. The conditions for such third-party
access to the electricity and gas supply networks are provided for in more detail in the
EnWG and particularly in the applicable ordinances governing the access to energy
supply networks (StromNZV and GasNZV). As a matter of principle, access must
be granted in a non-discriminatory, transparent and economically reasonable manner.
Furthermore, the law specifies the terms and conditions of network access agreements.
Regarding the electricity sector, network access is granted by allowing network
users (i.e., downstream or upstream network operators, energy suppliers and traders,
and supply customers) the transport of electricity on a contractual basis, normally either
all-inclusive contracts that cover both the network usage and the electricity supply or,
alternatively, on the basis of a separate network access agreement.
Gas network operators are required to offer entry and exit capacities in accordance
with the compulsory ‘two-contract model’ implemented in 2006 and applied on the
basis of a comprehensive cooperation agreement concluded by all gas network operators.
Accordingly, for the transportation of gas only two separate, tradeable contracts with
the respective entry and exit network operators for the feed-in (entry contract) and the
offtake (exit contract) of the gas are necessary. Thus, the transport customer does not
need to establish a transaction-dependent transport path based on the relevant network
connection points of interconnected networks.
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iii
Rates and tariffs
Germany
While the basic legal framework concerning network access tariff regulation is set out
in the EnWG, the procedure and the standards of review are substantiated within the
ARegV, StromNEV and GasNEV. Following a period of individual approvals of costoriented
network tariffs, since the beginning of 2009 the tariffs for the network access
have been determined by way of incentive regulation.
Under the regime of incentive regulation, the competent authorities determine
revenue caps for approximately 1,600 German energy supply network operators
(both on the distribution and transmission level). Deviating from the previous static
approval of cost-oriented tariffs, incentive regulation adds dynamic efficiencies by
setting incentives for efficient operation of the network. For each network operator, the
competent authorities define ex ante annual revenue caps, which include a general as
well as an individual efficiency target. Such efficiency targets will be formulated and
distributed across the regulatory period in a way that enables the network operator to
achieve and exceed these targets by employing realistic and reasonable measures. Within
the regulatory period of five years, network operators are allowed to collect the economic
benefits resulting from efficiency gains, effectively decoupling actual costs of the network
operation from admissible network tariffs. However, during the next regulatory period,
the benefit resulting from the improvement in efficiency must be passed on to the
customers through a decrease in network tariffs.
In order to determine the revenue cap for a network operator, the first step is
to calculate the relevant cost base level on the basis of the principles of a cost category
accounting scheme set out by the provisions of GasNEV and StromNEV. In principle,
the relevant cost base level is determined according to a cost analysis two years prior to
the beginning of the regulatory period on the basis of the prior closed business year.
Accordingly, for the second regulatory period (gas sector: 2013–2017, electricity sector:
2014–2018), the cost base level has been calculated in 2011 for gas network operators
and 2012 for electricity network operators based on the network-related cost data of the
financial year 2010 (gas) and 2011 (electricity), respectively.
In principle, the revenue caps will not be adjusted during a regulatory period;
however, the law provides for an adjustment of the revenue caps in limited circumstances
in order to reflect, inter alia, the annual inflation rate, a change of significant structural
parameters or cost factors, or unpredictable events causing undue hardship for the
network operator.
iv Security and technology restrictions
In Germany, there is no legislation that requires general safety measures comprehensively
applying to all critical energy infrastructure. However, sector-specific safety obligations
apply in particular to the operation of nuclear power generation based on the Nuclear
Power Energy Act and its respective ordinances.
In respect of network infrastructure, the EnWG provides for the rather general
obligation to ensure safe operation of any energy network that corresponds particularly
to the technical regulations of the German Gas and Water Association. In this respect,
the BNetzA is entitled to monitor compliance and, moreover, to implement further
safeguard measures if necessary.
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Moreover, the Foreign Trade and Payments Act, as well as the relevant ordinance
(the Foreign Trade and Payment Ordinance), authorise the BMWi to review and block
acquisitions of domestic target companies in key industries by non-EU investors if the
non-EU investor intends to acquire at least 25 per cent of the target company. If this
threshold is met, the BMWi will assess whether the acquisition endangers public order
or national security. For a potential intervention, the BMWi will assess whether the
acquisition would lead to a real and serious threat to public order or safety, and would
have an effect on the basic interests of German society. However, the German courts
would interpret these requirements in a fairly restrictive way. The review may occur
either upon application of the non-EU investor or be initiated by the BMWi ex officio.
While either the investor or the seller may voluntarily announce the acquisition plans and
thereby apply for a certificate of non-objection, the BMWi may only initiate an ex officio
review within three months of (1) the signing of the transaction, (2) the publication of
the decision to submit a public takeover offer, or (3) the publication of the acquisition
of control.
IV
ENERGY MARKETS
i Development of energy markets
In recent years, international trade has become an integral part of the energy markets
affecting German generation and wholesale supply market as well as retail markets. It
should be noted that the Nordic market – consisting of Denmark, Finland, Norway
and Sweden – has been connected to the electricity spot markets of Belgium, France,
Luxembourg, the Netherlands and Germany. Cross-border trade has become particularly
important recently since seven German nuclear power plants were shut down in March
2011. During this ‘nuclear moratorium’, Germany imported an average of 2,500MW
per day. However, due to high wind power input Germany’s export of electricity rose
again so that by the end of 2011 a slight export surplus was achieved.
The level of gas imports amounted to approximately 1,400TWh in 2010.
Approximately 40 per cent of the imported gas came from Russia; 26 per cent was
imported from each of Norway and the Netherlands. However, in view of certain
pipeline projects, it is likely that these values will increase significantly in the future.
For example, by the end of 2011 the Nord Stream pipeline and the Baltic Sea pipeline
(OPAL) were commissioned. Furthermore, the Northern German gas pipeline (NEL) is
soon expected to be completed.
A further notable development is the increasing volume and dynamics of the
national energy wholesale and energy trading market. The European Energy Exchange
(‘the EEX’) in Leipzig has become a major exchange for energy. The EEX operates market
platforms for trading in electric energy, natural gas, CO 2
emission allowances and coal.
The EEX also provides an intraday market to satisfy short-term demand or market shortterm
overcapacities. The exchange operates 24/7 without exceptions.
The increase of gas trading activities can partly be attributed to the merger of the
market areas. Since 1 October 2011 (the beginning of the new gas business year) the
German gas markets have been reduced to only two market areas: Netconnect Germany
and Gaspool. By way of contrast, in 2006 there were still 19 different market areas.
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With the integration of the former market areas Thyssengas H-Gas, Thyssengas L-Gas
and OGE L-Gas into Netconnect Germany, the first quality overlapping market area
was created. Hence, both gas of low calorific value (LCV) and gas of high calorific value
(HCV) can now be transported within one and the same market area.
The merging of market areas has also encouraged further liberalisation of the
gas retail markets. In recent cases, the BKartA indicated that, in consideration of such
newer developments, the geographical market for the supply of small end customers
is no longer limited to the network area of local or regional public utilities, but may
rather encompass the territory of the market area or potentially Germany. As regards
the electricity retail markets, the competition authorities had already found the retail
markets to be countrywide in scope as a consequence of introducing the regulated thirdparty
access in 2005.
ii Energy market rules and regulation
In Germany the markets for the sale of energy are not subject to specific (price) regulation.
Nevertheless, competition law applies to retail activities. In this respect, Section 29 of
the GWB is of particular relevance. A dominant supplier of electricity or pipeline gas
(normally a public utility) is, in principle, prohibited from abusing such position by
demanding fees or other business terms that are less favourable than those of other
utilities in comparable markets. While Section 29 of the GWB was originally intended
to expire by the end of 2012, the recent draft amendment of the GWB contains an
extension until 31 December 2017.
In respect of energy trading, the EEX is an exchange subject to the regulatory
framework of the Exchange Law Act, the legal supervision of the EEX and the oversight
of the exchange participants are carried out by the Saxon State Ministry of Economy,
Labour and Transport. Trading on the EEX is anonymous in order to ensure equal
treatment of all trading partners. The EEX is monitored through an independent
and autonomous market surveillance body. However, there is no monitoring by the
German Financial Services Regulator, BaFin. Further safeguard measures for ensuring
fair trading and the prevention of abuse follow from the EU regulation 1227/2011 on
wholesale energy market integrity and transparency (REMIT) of 2011. The regulation
prohibits market manipulation and insider trading and requires the disclosure of insider
information.
In this context, the BMWi presented draft legislation in May 2012 to establish
a market transparency department at the BKartA. This department shall, inter alia,
safeguard the transparency of the energy wholesale markets and perform regular market
investigations. However, the draft legislation has been discussed, and is controversial
because of the purely national perspective the new department is expected to assume
despite the international nature of the energy markets.
iii Contracts for sale of energy
The legal framework in Germany does not limit energy trading to exchange trading but
is also open to over-the-counter (‘OTC’) trade as well as bilateral agreements. In relation
to electricity, one third is covered by OTC trading. Concerning the trade of natural gas,
OTC is still the predominant form of trading.
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In Germany there are no specific administrative regulatory requirements governing
prices or contractual terms and conditions for the supply, sale and (bilateral) energy
trading. However, energy supply contracts have to consider indirectly the regulatory
framework for network access. In particular, energy supply contracts concluded as ‘fullsupply’
or ‘all-inclusive’ agreements must take the regulatory framework into account
because such agreements contain also the provision of network usage. By contrast, mere
supply contracts are normally concluded independently of network usage conditions.
Thus, the latter contracts allow for a more flexible portfolio management of energy
traders and large customers depending on current prices on the spot-market or the OTC
business.
We have already seen that bilateral supply and trading contracts have to comply
with the competition law regime that is enforced by the BKartA. In this context, Section
29 of the GWB becomes particularly relevant (see under IV.i, supra). Moreover, longterm
energy supply contracts may also be subject to general competition law scrutiny.
iv Market developments
As previously noted, the energy generation and wholesale markets in Germany are
becoming more and more international, in particular as a result of cross-border
supply and trading activities. This development will be supported by the envisaged
implementation of the European Network Codes in accordance with Regulations EC
714/2009 and 715/2009 by the European Network of Transmission System Operators
for Electricity and Gas (ENTSO-E and ENTSO-Gas) in cooperation with the Agency
for the Cooperation of Energy Regulators (ACER) and the Commission.
Furthermore, the energy turnaround leads to a shift in energy production, in
particular from nuclear to renewable energy sources but also from fossil fuels. In line with
this development, the exchange trade of renewable energy is becoming more frequent,
especially to compensate for short-term bottlenecks. Eventually, due to extensive
regulatory measures by the legislator and the competent authorities in previous years,
there is an ongoing liberalisation process in the retail markets.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
In Germany, electricity from renewable energy sources is mainly supported through
a feed-in tariff regime based on the basic principle that the costs of this scheme are
ultimately borne by the end consumers. The statutory framework for the prioritisation
and promotion of renewable energies, including the feed-in tariff regime, is set out in
the Renewable Energy Act (‘the EEG’). Accordingly, network operators are under an
immediate obligation, and as a priority, to purchase, transmit and distribute the entire
available quantity of electricity from renewable energy sources. In addition and most
importantly, operators of renewable energy facilities are entitled to receive fixed feed-in
tariffs from network operators in return for electricity fed into the network. The level
of such feed-in remuneration is normally guaranteed for a period of 20 years at the
level set at the time of the commissioning of the individual facility. In order to foster an
accelerated extension of renewable energy facilities, feed-in tariffs (for installations not
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Germany
yet commissioned) may be subject to a degression scheme. Accordingly, the guaranteed
feed-in tariffs will decrease year by year until the facility is eventually established and
commissioned. From a constitutional law point of view, it can be presumed that the
legislator is, in principle, not allowed to alter or repeal these positions retroactively after
the renewable energy facility has been commissioned.
Under the EEG, operators of renewable energy facilities may opt for selling the
electricity produced directly on the market instead of claiming the fixed feed-in tariffs.
This includes the option of a market premium scheme that compensates for potential
deviations between the fixed feed-in tariff level and actual revenues received by selling the
electricity on the (spot) market.
In the context of renewable energies, it is of particular relevance that the events
in Fukushima in Japan led to the German nuclear moratorium in March 2011. By
consequence, all German nuclear power plants had to undergo a safety evaluation.
Following these events, the German legislator decided to completely abandon the use
of nuclear energy by closing some of the oldest German nuclear power plants and by
adopting a gradual phase-out until 2022. Consequently, since then the administrative
bodies and the legislator have focused their decisions on an accelerated extension of
renewable energy sources. This regards particularly the promotion of electricity from
offshore wind power. In this regard, not only feed-in tariffs for offshore wind have been
increased, but also the Offshore Installations Ordinance has been amended in order to
simplify and accelerate approval procedures for offshore wind farm installations.
ii Energy efficiency and conservation
With regard to energy efficiency and conservation, a variety of technologies has been
promoted for the last years. This includes combined heat and power (‘CHP’) and
combined cooling, heating and power (‘CCHP’) generation. These systems are based
on the principle of simultaneous generation of multiple forms of useful energy within
a single system. The legal framework is provided by the Combined Heat and Power
Act (‘the KWKG’). The provisions of the KWKG function in a similar manner as the
aforementioned EEG rules. Thus, CHP or CCHP operators obtain a feed-in tariff, the
extent of which depends on the total capacity of cogeneration. This financial contribution
will effectively be paid by end consumers through higher network tariffs.
There have also been new statutory standards that aim at improving energy
efficiency in buildings. In particular, the Energy Saving Ordinance stipulates that between
2012 and 2020 standards for new buildings are to be gradually increased in order to
enhance energy efficiency. Furthermore, a recent amendment of German procurement
law aims at supporting energy-efficiency targets. Accordingly, the performance in relation
to energy efficiency has to be taken into account when awarding public contracts.
iii Technological developments
Recent events have led to technical enhancements particularly in the field of renewable
energies. The technologies necessary for the implementation of offshore wind farms
as well as offshore connection lines have to be developed under very difficult market
conditions and strict regulatory constraints. As a consequence, the undertakings involved
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face not only technological and regulatory difficulties but also a lack of financial, material
and personal resources.
Further technological improvements have been achieved in the development of
smartgrids and smart metering. In this context, the recent amendment of the EnWG
particularly strengthens smartgrids by equipping test regions with such technology in order
to assess the impact of intelligent power networks and their practical implementation.
In addition, the respective law also substantiates the implementation of smart metering.
So far, Germany has taken no significant part in the development of liquefied
natural gas (‘LNG’) as there is no single landing facility to accommodate LNG carriers
in Germany. Similarly, the technique of carbon capture and storage (‘CCS’) has no
considerable support in Germany. So far, the German legislator has not succeeded in
transposing the European CCS Directive 2009/31/EC into German law.
VI
THE YEAR IN REVIEW
From a regulatory point of view, the transformation of the European Third Energy
Package into the EnWG is of particular relevance. As a consequence, the German TSOs
have to comply with the rather strict ownership unbundling requirements and seek
certification.
Apart from that, the energy turnaround initiated by the German government
on the basis of its nuclear moratorium constitutes the main reason for the major policy
shift in the German energy sector. This development had an immediate impact on the
generation and wholesale supply level, in particular on prices during periods of high
demand. Furthermore, the gradual phase-out of nuclear power generation until 2022
initiated a shift towards an increased promotion of renewable energy resources, in
particular offshore wind power. However, both a lack of material and financial resources
as well as regulatory constraints are currently delaying the extension of offshore projects.
Furthermore, the envisaged extension of offshore facilities also requires an extension of
onshore transmission capacity. In this regard, the legislation in force, the Energy Line
Extension Act implemented in 2009 and the Grid Expansion Acceleration Act, do not
provide a sufficient and effective legal framework.
VII
CONCLUSIONS and OUTLOOK
German energy policy was subject to significant changes throughout the past year.
Certainly, the energy turnaround constitutes a major driver for past and also for future
legislation. However, the legislator and the competent regulatory authorities face
substantial challenges and difficulties particularly in relation to the envisaged extension
of offshore generation capacities and establishing sufficient onshore transmission
capacities. Remaining uncertainties have to be resolved in order to achieve the ambiguous
renewable energy targets and further to facilitate European cross-border energy markets.
As these topics are also constantly progressing at European level, it is fair to say that the
development of the energy turnaround will dominate the development of Germany’s
energy markets for the next couple of years, if not for the coming decades.
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Chapter 9
Greece
Euripides Ioannou and Dimitra Rachouti 1
I
OVERVIEW
Greece’s energy sector is viewed as an attractive prospect for both domestic and foreign
investment, a factor that significantly helps boost the Greek economy’s competitiveness,
particularly in the current market conditions. For this reason, the development of the
energy market is a fundamental principle of Greece’s development model, which aims to
create wealth by maximising domestic potential. The key policies in this regard are, first,
the protection and effective management of natural resources and the diversification
of the domestic energy mix by means of an accelerated transition to renewable energy
sources (‘RES’) and, second, the improvement of energy conservation and reduction of
energy consumption.
The liberalisation of the Greek energy market began in 1999 for the electricity
sector and in 2005 for the natural gas sector. In 2006, a bespoke legal framework was
implemented with a view to promoting the production of electricity from RES in order
to meet the national targets set by EU common policies for the reduction of greenhouse
gas emissions. This framework was extensively reformed in 2010 in order to further
simplify the relevant licensing process. Finally, in 2011, applicable Greek laws were
harmonised to align with the provisions of the EU’s 3rd Energy Package.
Currently, the main challenge encountered within the Greek energy market is
the significant use of fossil fuels for the production of electricity and, more generally,
for energy consumption. The use of lignite has been a strategic choice, despite its
environmental impact and consequences, due to the fact that it is a low-cost, abundant
source of fuel that is readily available within the country. Furthermore, the national
energy balance is dominated by imported hydrocarbons (mainly oil products and to a
lesser extent natural gas).
1 Euripides Ioannou is a partner and Dimitra Rachouti is an associate at PotamitisVekris Law
Partnership.
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Greece
In order to increase the competitiveness of the energy market and reduce the effects
of climate change, Greece’s main focus until 2020 is the achievement of the binding
national target of 20 per cent participation of RES in gross final energy consumption,
and, more specifically, 40 per cent participation of RES in electricity production, 20 per
cent in heating and cooling and 10 per cent in transport. An indicative target within
the energy conservation sector has also been proposed for the period leading up to 31
December 2019 in relation to the energy consumption levels of new buildings through
the utilisation of RES systems, co-generation of electricity and heat, and district heating.
This chapter is not intended to provide a detailed analysis of the Greek energy
market. Its aim is to provide a general overview of the current policies applicable in, and
the conditions of, the Greek energy market (focusing primarily on the electricity and
natural gas sectors), as well as of the trends and potential developments in the market.
ii
REGULATION
i The regulators
The Greek energy market is governed by a regulatory framework supervised by the
Ministry of Environment, Energy and Climate Change (‘YPEKA’) and the Regulatory
Authority for Energy (‘RAE’).
YPEKA’s primary responsibilities are the implementation of local energy policy
and the issuance of secondary legislation.
Following the reform of applicable energy legislation in 2011, RAE’s role was
greatly enhanced, making it the main decision-making authority regarding the regulation
of the Greek energy market. In addition, RAE also issues non-binding guidelines and
recommendations. In summary, RAE’s key responsibilities are:
a the monitoring the availability of energy supply;
b the issuance of licences relating to electricity and natural gas activities;
c the issuance of codes of management and the determination of the tariffs for
access to the transmission and distribution systems of electricity and natural gas,
as well as the tariffs for the provision of public utilities services to consumers;
d the supervision of fair competition;
e the settlement of disputes within the energy sector; and
f the imposition of penalties in the event of breaches of applicable rules and
regulations.
With respect to the oil market, RAE’s regulatory powers include the monitoring of
the applicable tariffs, marketing of oil products in Greece, access by third parties to
oil security reserves, opining on the issuance of codes relating to the licensing of oil
products and oil security reserves, and, if, necessary the imposition of a price ceiling on
oil products.
RAE is a independent legal entity subject to parliamentary and judicial control.
It should be noted that due to the current domestic market conditions RAE is currently
understaffed, which, in some cases, adversely affects the performance of its functions.
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ii
Regulated activities
Greece
Electricity
Within the electricity sector, a licence is required for each of the production, supply and
trading of electricity.
With regard to the production of electricity, the licensing process has three phases.
First, RAE issues a generation licence after assessing the technical and financial feasibility
of the project. Second, following the determination and agreement of the technical and
financial terms of interconnection and the completion of the environmental approval
process, the producer receives an installation licence, which allows the construction of
the project’s facilities. Finally, once the project’s commissioning is complete, an operation
licence is issued.
Although this structure is similar for both RES producers and producers using
conventional sources, the licensing process for RES producers is faster, with certain
stages running in parallel and simplified procedures applicable.
It should be noted that the issuance of licences for offshore wind parks has been
suspended since 25 November 2011. At present, RAE will only evaluate applications
submitted prior to such date.
The supply of electricity is divided in two distinct licensed activities: a crossborder
electricity trading licence, which requires share capital of at least €60,000 and a
licence for the supply of electricity permitting both cross-border transactions and retail
sale of electricity to end-users, which requires a share capital of at least €600,000.
Natural gas
Within Greece’s gas sector, licences are required in order to own and manage an
independent natural gas transmission system, as well as for the distribution of natural
gas. Such licences are issued upon application by RAE. In certain situations (e.g., if
a transmission system serves the public interest, a distribution grid is subsidised by
domestic or EU sources, or multiple applications are submitted for a particular area), a
tender process may be concluded.
A licence issued by RAE is also required for the supply of natural gas.
Currently, the key supplier of natural gas in Greece is the government-owned
Public Gas Corporation SA (‘DEPA’), excluding the suppliers of the regions of Attiki,
Thessaloniki and Thessalia, who are independent companies, each of which DEPA owns
51 per cent. A similar regime will be introduced in the near future in the regions of
Eastern Macedonia and Thrace, Central Macedonia and Sterea Ellada and Evia, in which
three new companies are in the process of being incorporated.
Hydrocarbons
Upstream
The Greek state has a statutory exclusive right to the exploration and exploitation of
hydrocarbons in regions where it possesses sovereign rights. The recently established
company Hellenic Hydrocarbon Resources Management SA (‘HHRM’) has been
appointed to manage such rights of the Greek state. In particular, HHRM may assign
the exploration right to third parties following a relevant invitation for the submission
of applications, and subject to the approval of YPEKA. The same process applies to the
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assignment of seismic and other geological exploration rights. The contractor performs
the seismic activities at its own expense and has the right to sell the results to third parties.
A different assignment process applies to exploitation rights, which are assigned
on the basis of either lease agreements or a distribution agreements relating the
hydrocarbons produced entered into between HHRM and the respective concessionaires.
Such agreements are concluded following a tender procedure or, for areas not included in
the tender, the submission of applications, or through an open-door invitation process
for areas generally available or for which similar procedures were previously unsuccessful.
The agreements must be approved by YPEKA, otherwise they are null and void. The
concessionaire takes on the financial and business risk and in the event of a positive
outcome it has the exclusive right to produce and sell the hydrocarbons. The Greek state
has the right to participate in the above agreements through a joint venture with the
concessionaire.
Recently, the Greek state launched an open-door tender process for the exploration
and exploitation of three areas in Patras Gulf, in northern Greece: Epirus and Ioannina,
and at West Katakolo pursuant to lease agreements. The deadline for the submission of
offers is 2 July 2012. Furthermore, 2 March 2012 was the deadline for the submission
of applications to participate in non-exclusive seismic surveys in western and southern
Greece. The results of the surveys are expected to be released in September 2012.
Downstream
The following activities are subject to the licensing regime:
a oil refining;
b marketing of bio fuels;
c trade of oil products, tax-free shipping and air fuels, liquid gas and asphalt;
d transmission of oil through pipelines;
e retail sale of liquid fuels, heating oil and bottled liquid fuels; and
f bottling of liquid gas.
YPEKA issues the licences under (a) to (d), while licences under (e) to (f) are issued by
competent local authorities.
A special regime applies for the marketing of biodiesel used in transports,
pursuant to to an annual programme maintained by YPEKA, which determines the exact
quantities to be marketed for the next year (132,000 kilolitres for 2012), the allocation
of such quantities to specific companies, and the required percentage at which biodiesel
must be blended with diesel (6.5 per cent).
iii Ownership and market access restrictions
Greek law imposes a number of restrictions with a view to protecting its interests, the
interests of national security and the availability of supply. Approval processes apply
under Greek law in the event of transfers of control and assignments. Such processes
vary among the energy sectors. The usual time frame for such approval processes is
approximately three to four months, however, there may be instances in which such
deadlines may be exceeded.
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Electricity
The government-owned Public Power Corporation SA (‘PPC’) is the exclusive owner
of the national electricity distribution grid of and the sole supplier of electricity to the
consumers on the non‐interconnected islands.
Small RES stations, which are not subject to the usual licensing process, as well
as licences required by photovoltaic (‘PV’) stations (irrespective of capacity), may not
be transferred prior to the commencement of their commercial operation, unless the
company acquiring the licence is a wholly owned subsidiary of the company transferring
the licence.
Natural gas
In the event that a person (individual or legal entity) acquires a shareholding in a natural
gas transmission system operator, if the participation of an existing shareholder exceeds
20 per cent, 33 per cent or 50 per cent, or the operator becomes a subsidiary of a
shareholder, an obligation of previous notification and approval of RAE applies, failing
which the exercise of the voting rights of the shareholders has ipso jure no effect.
If there is a change in the legal form or the shareholding structure of a holder of
a licence relating to natural gas activities, the licence must be amended. With respect
to listed companies, this requirement applies only if if the change results in a change of
control.
It should be noted that in view of the envisaged privatisation of the electricity
and natural gas transmission system operators, the Greek legislator recently abolished
the provisions regarding the privilege of the state to retain, directly or indirectly, control
of the operators regardless of the ownership structure as objecting to the EU legislation
(free movement of capitals).
Oil
The Greek state is statutorily the sole shareholder of HHRM. In addition, the
concessionaires of upstream petroleum rights may not, without the prior consent of the
Greek cabinet of ministers, be controlled, directly or indirectly, by non-EU entities.
iii
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Law 4001/2011, which implemented the provisions of the 3rd EU Energy Package into
national law, adopted the unbundling model of independent transmission operators for
both the electricity and natural gas sectors.
In order to ensure that transmission system operators comply with the unbundling
requirements, Law 4001/2011 prohibits any person (individual or legal entity) (1)
from having direct or indirect control or any other right over a producer or supplier
of electricity or natural gas and simultaneously having such control or rights over an
operator of a transmission system of electricity or natural gas or over the transmission
system itself and vice versa; and (2) from appointing or being appointed as a member of
the board of directors or other management bodies of the operator and simultaneously
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having direct or indirect control or any other right over a company acting as producer or
supplier of electricity or natural gas.
Before the implementation of the unbundling rules in the electricity sector, PPC
acted as a vertically integrated undertaking (producer, supplier of electricity and owner
of both the national transmission system and the national distribution grid (including
the grid of the non-interconnected islands)). In 2001, PPC assigned the management
of the national electricity transmission system to its subsidiary, Hellenic Transmission
System Operator SA (‘HTSO’). PPC retained both ownership and operation of the
distribution grid.
After the 2012 unbundling the following changes occurred.
Electricity
PPC assigned both the ownership and management of the national transmission system
to a wholly owned subsidiary company called the Independent Power Transmission
Operator SA (‘ADMIE’). ADMIE commenced operations on 1 February 2012 and is
entirely independent from its parent company in terms of legal status, management and
operation and it retains effective decision-making rights.
HTSO became the company now known as Operator of the Electricity Market
SA (‘LAGIE’), which also commenced operations on 1 February 2012 and is responsible
for the management of transactions in the wholesale electricity market.
PPC has retained ownership of the national electricity distribution grid but has
assigned its management to the Hellenic Electricity Distribution Grid Operator SA, a
wholly owned subsidiary of PPC.
Natural gas
In the natural gas sector, even prior to the implementation of the unbundling
requirements, the ownership and management of the national gas transmission system
had already been transferred from DEPA to DESFA. Under the current regime, DESFA
has retained ownership and operation of the transmission system and is required to be
certified by RAE as an unbundled operator to ensure its independence from its mother
company DEPA or any of its affiliated companies.
ii Access to the transmission, transportation and distribution systems
Greek law ensures full access on a non-discriminatory basis to the transmission and
distribution systems in both the electricity and natural gas sectors.
Electricity
Producers, traders and suppliers of electricity acquire the right of access to the system
once they have been entered into the register maintained by LAGIE. This does not apply
in respect of RES producers, who gain access by entering into bilateral power purchase
agreements with the competent operators. Under certain circumstances, access may
be denied to RES projects if the interconnection area is classed by RAE as one that is
saturated due to technological restrictions or overload. In such areas the issuance of a
generation licence is prohibited until capacity becomes available.
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Natural gas
In the natural gas sector, users may participate in the national gas system once they have
been entered in the register kept by DESFA and are entitled to make use of transmission
services, liquefied natural gas (‘LNG’) facilities, storage facilities and reserve of capacity
on the basis of bilateral agreements with DESFA.
iii Access tariffs
Electricity
With respect to electricity, RAE determines the tariffs taking into account the operators’
proposals. The calculation methodology takes into account the production or purchase
cost of electricity plus a reasonable return on invested capital. The aim is that the tariffs
reflect, to the extent possible, the cost imposed on the system by the users’ installations,
and help users manage the demand and load variation.
Natural gas
In the natural gas sector, YPEKA sets out the calculation methodology for the applicable
access tariffs. Using such methodology DESFA determines annually the basis of the
tariffs for transmission services and the use of LNG facilities. Furthermore, the final
tariffs are determined in a manner that ensures that DESFA receives 90 per cent through
charges imposed on the maximum capacity reserved by the users and 10 per cent through
charges imposed on the quantities transmitted through the system or gasified at the LNG
facilities on behalf of the users.
iv
ENERGY MARKETS
i Organisation of energy markets
Electricity
The wholesale electricity market is organised as a mandatory pool based on bilateral
commercial relations between consumers and suppliers and producers. The operator
does not interfere in such bilateral agreements, but it is responsible for the coordination
of the settlement of such transactions.
In particular, the wholesale market is structured as a day-ahead market. LAGIE
performs a day-ahead scheduling with the aim of achieving the optimum 24-hour
operation of the electricity generation units for the next day (imported electricity also
being considered) in order to meet the demand of consumers and exporters at the
minimum cost. The day-ahead scheduling is remunerated at the marginal system price,
which is equal to highest price quoted among the group of lowest bidder units that must
operate in order to meet the demand of next day. Suppliers and producers or importers
of electricity buy and sell electricity at the system marginal price.
In addition to the foregoing, a real-time market of ex post clearing of deviations
between the real quantity of electricity finally produced and the quantity that was
estimated to be produced also operates.
Furthermore, LAGIE enters into bilateral agreements with producers in relation
to ancillary services (transmission of electricity from the points of injection to the points
of consumption) following tender procedures.
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Apart from the wholesale market described above, a market of long-term guarantees
also exists whereby producers are remunerated to keep their units at operational alertness
on an annual basis and recover part of their capital cost in this way. The market operates
through bilateral contracts between producers and suppliers. LAGIE may hold auctions
in order to facilitate the conclusion of such contracts.
Retail sale of electricity is based on bilateral agreements between suppliers and
final consumers. With the aim of linking the retail prices to the wholesale prices, the
prices for the supply of electricity to high voltage consumers were liberalised in 2008 and
are freely negotiated between the contracting parties, and the prices for medium voltage
consumers were also liberalised in 2010. The prices for the supply of electricity to low
voltage consumers remain subject to regulation until 30 June 2012, and for this reason
must be approved by YPEKA.
In addition to the foregoing tariffs, all consumers in Greece are burdened with
a surcharge set by the Ministry for provision of public services to vulnerable categories
of consumers (i.e., consumers on non-interconnected islands and consumers in a poor
financial condition) in order that the supply of electricity is offered on similar terms for
all categories of consumers.
Natural gas
In the natural gas sector, DESFA prepares weekly and daily schedules of transactions, as
well as monthly and annual schedules for the unloading of LNG during the year. The
natural gas market is based on agreements between DESFA and the users of the system
for provision of transmission services (reception of natural gas quantity from one or more
entry points, transmission through the system and delivery at one or more exit points)
and LNG services (LNG cargo unloading and discharge, detachment of the LNG vessel,
temporary storage, regasification of LNG cargo).
Retail sale of natural gas to final consumers is based on bilateral agreements
with the suppliers, and prices are freely negotiated between the contracting parties. The
pricing policy of the suppliers must, however, comply with the terms of their licence
and be notified to RAE. In certain circumstances, RAE may determine a maximum
profit margin for a period of up to two months if it considers that prices in effect breach
applicable competition rules.
ii Market developments
With the aim of diversifying the Greek energy mix by increasing RES penetration and
limiting or, preferably eliminating, the constraints of the liberalised energy market, the
following policies are currently being considered:
a Details of an Energy Roadmap for 2050 are being discussed, which evaluates
alternative scenarios and policies for the achievement of proposed national and
EU targets for the reduction of greenhouse emissions by 60 to 70 per cent by
2050 compared with 2005, 85 to 100 per cent electricity generation from RES,
total penetration of RES in gross final energy consumption by 2050, significant
reduction of oil consumption, increased use of biofuels in transportation sector
at a level of 31 to 34 per cent by 2050, development of decentralised production
units and smart grids.
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b
c
d
Promotion of the use of solid waste for the production of electricity (mainly in
cement industries).
By 2014–2015, the Greek electricity market must gradually shift, via regulatory
changes and market restructuring, to the EU target model for market coupling
and price coupling, according to the requirements of the 3rd EU Energy Package
(which is not entirely compatible with the currently applicable mandatory pool
system).
Revisiting the scheme of financial support to RES producers. This is still an open
issue, however, the memorandum agreed between Greece and the troika 2 favours
the feed-in premium scheme, according to which RES producers are paid with
the system marginal price plus a premium, instead of the applicable guaranteed
feed-in tariff regime.
v
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
The production of electricity from RES is regulated by a bespoke legal framework that
implements a licensing process with parallel stages, as opposed to serial stages that were in
effect in the past. It also implements a simplified licensing process for projects with capacity
less than the limits set by law per technology and simplified environmental procedures
containing favourable provisions for the installation of PV systems on buildings.
The installation of RES projects in Greece until 2020 takes place on the basis
of an allocation schedule determining the desired proportion of installed capacity per
technology. Such allocation aims at the achievement of the target of the contribution of
energy produced from RES to the gross electrical energy consumption by a share of 40
per cent by 2020. In particular:
Category of RES technology By 2014 Until 2020
Hydroelectric Less than 15MW 300MW 350MW
More than 15 MW 3,400MW 4,300MW
Total 3,700MW 4,650MW
Photovoltaic Farmers 500MW 750MW
Other producers 100MW 1,450MW
Total 1,500MW 2,200MW
Solar thermal 120MW 250MW
Wind (including offshore) 4,000MW 7,500MW
Biomass 200MW 350MW
The table above demonstrates that priority is given to the hydroelectric and wind
technologies; however, photovoltaic technology has higher market growth.
2 The European Commission (EC), the International Monetary Fund (IMF) and the European
Central Bank (ECB).
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ii
The feed-in tariff system
Greece
Since 2006, a feed-in tariff regime has been established for the financing of RES projects,
which ensures fixed tariffs for 20 years. The feed-in tariff scheme is entirely financed via
a designated account of LAGIE, primarily funded by a special levy applied to electricity
bills as well as the proceeds from the European Emission Allowance auctions until 2015.
It should be noted that, at present, the designated account is in deficit which, may, if not
covered, jeopardise the payment of tariffs to the RES producers. As a long-term measure,
in order to secure the viability of the designated account until 2020, it has been proposed
that the feed-in tariff scheme be revised so as to reflect the diluted cost of installation of
RES technologies and the increasing cost of funding.
Specific tariffs apply for PV projects, which have been reduced since 1 February
2012 in light of the domestic market conditions (by 12.5 per cent for onshore PV
projects and 5 per cent for roof-top PV projects) and which will be reduced further (by
7 per cent) per half-year until August 2014. Finally, a incentive was recently introduced
for PV projects, according to which feed-in tariffs are increased by 10 per cent provided
that at least 70 per cent of the equipment of the station is made in an EU Member State
or a country of the European Economic Area. The framework for the implementation of
the above subsidy is yet to be introduced.
iii Energy efficiency and conservation
The improvement of energy conservation and the reduction of energy consumption is
one of the main objectives of the national energy policy. In order to achieve this, the
applicable legal framework sets outs energy-efficiency measures for the building sector,
cost-efficient actions concerning final consumption and envisages the creation of an
energy services market, which include the following:
a An energy-efficiency status certification process applies for residences and
professional buildings with a surface area exceeding 50 square metres, which
is carried out by energy inspectors, licensed specifically for such purpose. The
energy-efficiency certificate is a prerequisite for the sale or lease of the relevant
property.
b In 2011, YPEKA launched a programme aimed at increasing the energy efficiency
of household buildings constructed before 1989, primarily by the provision of
low-interest loans. Such programme will remain in force until 31 December
2017. The programme is financed through a designated revolving fund, funded
by EU and national sources (which have provided circa €241 million) as well as
by the Greek private sector (which has provided circa €400 million). In March
2011, YPEKA launched a second programme, exclusively aimed at municipalities,
which will be in force until 31 May 2015. The total budget of this programme is
€107 million and is based on the premise that eligible municipalities may obtain
up to 70 per cent of their financing from the programme’s funds and may provide
their own funding for the remaining 30 per cent.
c There is a legal obligation for mandatory use of natural gas, installation of thermal
solar systems or other RES technologies in public buildings as well as a mandatory
quota of clean vehicles in the public sector.
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d
e
f
g
Incorporation of energy services companies (‘ESCOS’) for the provision of energyefficiency
services to end-users by taking on the business and financial risk. Banks
or other financial institutions can participate in order to finance the services. The
remuneration of ESCOS amounts to a percentage of the contractually agreed
financial benefit for the end-user due to energy efficiency practices.
Apart from the aforementioned measures, energy efficiency in buildings is also
promoted through a special programme for the installation of roof-top PV
projects, which was launched in 2009 and will be in force until 31 December
2019. The programme encourages individuals and small enterprises that own
buildings to install roof-top PV projects with capacities of up to 10kW (5kW in
the non‐interconnected islands) through an attractive feed-in tariff mechanism
with fixed tariffs for 25 years. The income from the production of electricity is
tax-free.
YPEKA implements pilot energy-efficiency programmes for schools, villages and
islands in Greece, whole neighbourhoods and hospitals.
Law 4001/2011 promotes the extensive substitution of the existing metering
systems of final consumption by smart systems. The framework for the substitution
has, however, not yet been established due to lack of issuance of the required
secondary acts.
vi
THE YEAR IN REVIEW
Given the current domestic market conditions, national strategy focuses on two
ambitious keystones:
First, a strategic alliance has been forged with Cyprus and Israel in order to jointly
promote the exploration and exploitation of hydrocarbons in the eastern Mediterranean
region and to create new routes of delivery of hydrocarbons to Europe. Memorandums
of understanding have already been signed in this regard between the aforementioned
countries. At the same time, the Greek state has shown commitment to pursue the
exploration and exploitation of potential petroleum reserves in the Ionian Sea in western
Greece.
Second is the introduction of the Helios project, through which electricity
produced from domestic photovoltaic stations is exported to other EU Member States.
The underlying concept of the project is based on the idea that Greece is an ideal place
for efficient solar production because of the hours of sunshine per year. The plan is
to develop solar installations of a total production capacity of 10GW and export the
electricity produced to northern EU countries. There are, however, key issues that need
to be addressed prior to the roll-out of the programme, such as (1) the applicable financial
support regime in respect of the exported electricity, (2) the transportation method to
be used in relation to the exported electricity (i.e., physical or virtual transmission);
(3) matters related to the level and terms of participation of local industries in the
programme; and (4) the technical challenge of constructing a grid capable to transport
the energy produced.
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In addition to the above, pursuant to the Memorandum with its creditors, Greece
has the following obligations, which are aimed at making the energy market more
competitive:
a to provide third parties with access to units producing electricity from lignite and
hydroelectric units, an activity that is currently within the remit of PPC; and
b to privatise DEPA, DESFA and PPC.
Another very important matter is the routing of the natural gas transmission pipeline
from Azerbaijan to Europe through Greece, which will contribute to the diversification
of natural gas suppliers and delivery routes throughout Europe. In March 2012, the Shah
Deniz II consortium, the developer of Azerbaijan’s gas field, confirmed ITS selection of
the proposed route – the Trans-Adriatic Pipeline – which passes through Greece.
vii
CONCLuSIONS and OUTLOOK
Investment in energy is a key factor in driving Greece out of its current economic crisis.
Greece’s climate presents a considerable comparative advantage when it comes to wind
and solar project development and the Helios project is a vision to capitalise on this.
There are, nevertheless, a number of challenges to overcome, namely the funding of
the feed-in tariff regime on a sustainable basis, the need for grid upgrades and, most
importantly, availability of financing. There is also reasonable optimism regarding the
prospects of the exploration and exploitation of hydrocarbons recently promoted by
the Greek government, which, if successful, will certainly give a boost to the domestic
economy.
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Chapter 10
India
Akshay Jaitly, Sitesh Mukherjee, Neeraj Menon and Vibhu Sharma 1
I
OVERVIEW
As energy consumption burgeons with economic development, urbanisation and
population growth in India, demand outstrips supply and resources available. The
government of India commenced liberalising the energy market in 1991. Thereafter, a
spate of legislative and policy changes in the electricity as well as the oil and gas sectors
have been brought into force to bolster energy output, increase private participation
and price efficiency. To meet domestic energy requirement, India imports significant
quantities of coal, oil and natural gas. Even in pursuing its nuclear energy agenda, India
is dependent on uranium imports. In addition to relying on imports, India has made
significant investment in energy resources in over 30 countries. 2 Dependence on fossil
fuels is likely to continue at least into the near future; however, energy security is also
being pursued through clean energy. The Ministry of New and Renewable Energy (‘the
Renewable Energy Ministry’) forecasts that the annual clean energy investment in India
will grow by as much as 763 per cent over the next decade.
II
REGULATION
i The regulators
The power sector is governed by the federal government through, primarily, the Ministry
of Power and the Renewable Energy Ministry. The Department of Atomic Energy 3 is in
1 Akshay Jaitly and Sitesh Mukherjee are partners, Neeraj Menon is a counsel and Vibhu Sharma
is an associate at Trilegal.
2 Some of these countries are Australia, Brazil, Colombia, Egypt, Iraq, Libya, Nigeria, Sudan,
Venezuela, Vietnam and the United States.
3 Which is directly under the Prime Minister’s charge.
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charge of nuclear energy. The Electricity Act 2003 is the primary statute that governs
generation, transmission, distribution and trading of electricity. The Electricity Act
provides, inter alia, for the formulation of the National Electricity Policy (formulated
in 2005), the Tariff Policy (formulated in 2006), establishment of independent
electricity regulatory commissions at the central level (the Central Electricity Regulatory
Commission (‘the CERC’)) and state level (the state Electricity Regulatory Commissions
(‘SERCs’)) and the setting up of the Appellate Tribunal for Electricity. The relevant
SERCs exercise jurisdiction over intrastate electricity regulatory matters (including
tariffs), whereas the CERC exercises jurisdiction over all interstate electricity regulatory
issues (also including tariffs).
Along with the Department of Atomic Energy, nuclear energy in India is regulated
by the Atomic Energy Regulatory Board, set up under the Atomic Energy Act 1954. The
government is also in the process of setting up a statutory, independent and autonomous
Nuclear Safety Regulatory Authority.
The Ministry of Coal administers all issues in relation to coal. In the last few
months, due to a shortage in coal availability, there has been immense lobbying on the
part of power producers for assured coal supplies by the government. Amidst this, the
setting up of an independent coal regulator for allocating coal blocks and regulating coal
prices is being deliberated upon. The draft Independent Coal Regulatory Authority Bill
2012 is pending consideration.
The Ministry of Petroleum and Natural Gas (‘the MoPNG’) deals with issues
relating to petroleum, natural gas, coal bed methane, shale gas and other petroleum
products. Along with exploration and production, the MoPNG also monitors its supply,
distribution, marketing and pricing. The Oilfields (Regulation and Development) Act
1948 and Petroleum and Natural Gas Rules 1959 provide the regulatory framework for
domestic exploration and production of oil and gas. The Petroleum Act 1934 controls
issues in relation to import, transport, storage, production, refining and blending of
petroleum.
The Directorate General of Hydrocarbons (‘the DGH’) is the upstream regulatory
body in charge of issues relating to exploration and production of oil and gas. Since
the DGH is an entity under the administrative control of the MoPNG, there has been
discussion recently of constituting an independent upstream regulator. The Petroleum
and Natural Gas Regulatory Board (‘the PNGRB’), constituted under the Petroleum and
Natural Gas Regulatory Board Act 2006, is the midstream and downstream regulator.
The PNGRB regulates the refining, storage, transportation, distribution, marketing and
sale of petroleum, petroleum products and natural gas.
ii Regulated activities
Electricity generation, including captive generation, is a delicensed activity. 4 While
generation activities can be freely undertaken without a licence, approvals and procedure
4 Hydropower projects that exceed the capital cost notified by the Government need concurrence
of the Central Electricity Authority.
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under other laws for land acquisition, environmental, corporate and labour compliance
must be adhered to.
Electricity distribution activities (except for distribution of electricity in
rural areas) require a licence from the relevant SERC. Electricity trading is a distinct
recognised activity for which a separate licence is required from the CERC or an SERC
(for interstate and intrastate trading respectively). However, distribution licensees can
undertake electricity trading activities without a trading licence. Licences are awarded by
the CERC for interstate transmission activity by way of a competitive bidding procedure
in accordance with CERC regulations. For intrastate transmission services, licences are
awarded by the relevant SERC under relevant regulations.
The DGH awards licences through international competitive bidding for natural
gas exploration blocks under the New Exploration Licensing Policy (‘the NELP’) rolled
out in 1999. The production-sharing contract (‘PSC’) under the NELP programme
stipulates conditions regarding pricing and sharing of total product obtained with the
government. The coal bed methane (‘CBM’) policy (formulated in 1997) offers blocks
for exploitation of CBM through open competitive bidding system, in a manner similar
to the NELP.
Petroleum, natural gas and city gas distribution (‘CGD’) networks can be
developed either through an expression of interest to the PNGRB or under competitive
bids invited by the PNGRB. Under the expression of interest route, upon a receipt of
interest the PNGRB must publicise it to receive proposals or comments from different
entities, and may invite competitive bids or allow for the proposal (with or without
modification).
iii
Ownership and market access restrictions
Over the past decade, the government has progressively liberalised the energy sector,
although government companies continue to be active players. The government actively
seeks to promote domestic and foreign investment in the energy sector. Up to 100
per cent foreign direct investment (‘FDI’) is permissible in generation (except nuclear
power), transmission and distribution of electricity as well as in the oil and gas sector 5
without prior regulatory approval. Such investments are subject to sector-specific laws
and policies. Interestingly, in comparision, China permits FDI up to 75 per cent in the
electricity sector and up to 85 per cent in the oil and gas sector.
State-owned as well as private entities play a significant role in electricity
generation. The interstate transmission system is mainly owned and operated by Power
Grid Corporation of India Limited (‘PGCIL’), a state-owned company, and the intrastate
transmission system is owned and maintained by state utilities. The government is
looking to increase private participation to strengthen transmission networks with
the aim of bolstering transmission capacity and to cater for the increased generation
capacity through competitive bidding and the recently introduced viability gap funding
5 Investments in petroleum refining under taken by government-owned entities, only up to 49
per cent FDI is permitted subject to approval.
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model public private partnership (PPP) structure for setting up transmission networks.
Electricity distribution is largely in the control of government distribution utilities,
but has also been privatised in certain regions (such as Delhi, Orissa, Mumbai and
Jamshedpur). The Electricity Act allows private entities to operate as parallel licensees,
though this arrangement is yet to be meaningfully brought into practice.
In India, the ownership of all mineral resources, including oil and gas vests with
the government, and is administered through the MoPNG. Gas Authority of India
Limited (‘GAIL’) and Oil and Natural Gas Company (‘ONGC’) are the largest owners
of oil and gas pipelines in the country. Private players are increasingly entering the CGD
space.
iv Transfers of control and assignments
While there are no restrictions on transfer of control or assignment of a generating
company, for generating stations set up pursuant to certain renewable energy policies
or by competitive bidding (for thermal or hydro-electric projects), however, there is a
shareholder lock-in period for the developer. For instance, in thermal or hydro-power
projects set up under competitive bidding there is a share-holding lock-in of 51 per
cent up to two years after the commissioning date of the power station, and 26 per
cent minimum shareholding requirement for three years thereafter for the original
shareholders of the generating entity that has signed the power puchase agreement
(‘PPA’). Lenders have also in some instances in the past required the sponsors to retain
shareholding in the project SPV during the term of the loan.
Holders of licences for oil and gas exploration cannot transfer rights, title or
interest under the licence without prior written permission from the government. A
party may assign or transfer, a part or all of its participating interest under the PSC,
with prior consent of the government. It must be noted that the change of control of a
party is also deemed to be an assignment under the PSC, requiring the consent of the
government.
Other than these sector specific restrictions, provisions of the Companies Act 1956,
Competition Act 2002, and the Securities and Exchange Board of India (Substantial
Acquisition of Shares and Takeovers) Regulations 1997 (applicable to listed companies)
will apply with respect to change in shareholding through mergers and acquisitions.
Iv
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Prior to the reforms in the electricity sector, state electricity boards (‘SEBs’) constituted
under the Electricity (Supply) Act 1948 were composite entities performing generation,
transmission and distribution function in a particular state. Under the Electricity
Act, SEBs were required to be unbundled into separate generation, distribution and
transmission companies. Several states had initiated unbundling activities much prior to
the enactment of the Electricity Act and most have now completed the process.
Exploration of oil and gas is a separately licensed activity. Transportation,
distribution and marketing activities in the oil and gas sector are yet to be unbundled.
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There are, however, proposals of unbundling of transportation activity from that of
distribution or marketing. In fact, regulations that authorise carrying out of transportation
activity, clearly stipulate that the authorised entity shall adhere to the requirements of
unbundling of transportation from distribution or marketing as and when so decided
by the PNGRB.
ii Transmission/transportation and distribution access
In the electricity sector, transmission licensees must provide non-discriminatory
open access to its transmission system for use by other persons (including electricity
distributors, traders and generating companies). Open access to distribution networks
is also granted to bulk power consumers (i.e., consumers of above 1MW), to procure
electricity at unregulated prices from entities other than the area distribution licensee.
Recently, the Ministry of Power issued a direction to the CERC to take all necessary steps
to implement provisions on open access as contained in the Electricity Act, to the effect
that SERCs do not continue to regulate the tariff for electricity supply to bulk power
consumers.
Natural gas transporters must declare capacity available for common carriage
on a monthly basis. For petroleum pipelines, draft guidelines for declaring pipelines
transporting petroleum and petroleum products as common carriers are currently
pending finalisation. For CGD networks, the PNGRB has the discretionary powers to
allow exclusivity for laying, building or expanding CGD network for the duration of the
economic life of the project (about 25 years). Exclusivity exempting common carriage
may also be provided for the first five years for CGD networks.
iii Rates
Under the Electricity Act, transmission schemes are implemented either through the
tariff-based competitive bidding process or under a cost-plus mechanism where a
regulated tariff is determined by the relevant electricity commission. CERC has adopted
a new interstate power transmission charge regime in 2011, with a ‘point of connection’
method for calculating interstate transmission charges and losses. The new regulations
aim at developing a uniform transmission charge-sharing mechanism among grid
constituents. Tariff for electricity distribution, comprising wheeling charges and cost of
supply, is levelled and determined on a cost-plus basis by the relevant SERC. Generally,
the tariff paid by low-income households for electricity is lower and is cross-subsidised
by high-end industrial and commercial consumers.
The PNGRB has enacted regulations for determination of transportation tariff
for petroleum and petroleum products; natural gas pipelines; and CGD network. The
tariff for such pipelines will be determined taking into consideration a reasonable rate
of return on the normative level of capital employed plus a normative level of operating
expenses in the relevant pipeline.
iv Security and technology restrictions
Cyber security of energy infrastructure
With sophisticated energy infrastructure and now smartgrids being proposed, cybersecurity
concerns are paramount. The Information Technology Act 2000 addresses
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hacking and security breaches of information technology infrastructure. While a
comprehensive cyber-security law and policy is yet to be formulated, the government has
formulated a crisis management plan for countering cyber attacks and cyber terrorism
for implementation by government entities and critical sectors. Recently, the government
announced that measures are being taken to formulate a legal framework to address cyber
crimes, cyber attacks and security breaches of information technology infrastructure.
In relation to the electricity sector, the Indian Electricity Grid Code 2010 requires
all utilities to have in place a cyber-security framework to identify the critical cyber assets
and protect them so as to support reliable operation of the grid.
Technology transfer
Technology transfers into India are permitted in all sectors, including energy. All
payments made for technology transfers into India are subject to Indian exchange control
regulations. Export of technology transfers for specific sectors requires a licence under
India’s Foreign Trade Policy. In the context of the energy sector, export of technology in
relation to nuclear-related equipment and information technology requires obtaining a
licence by the Director General of Foreign Trade. Such licence is awarded on a case-bycase
basis.
V
ENERGY MARKETS
The National Electricity Policy 2005 envisions 85 per cent of power from new capacities
being contracted through long-term PPAs and the remaining 15 per cent power capacity
through market mechanisms. It is also expected that more merchant capacity will be
available in the next few years as the power sector begins to successfully attract equity
investors.
The power market is dominated by long-term contracted power. For thermal
power projects (coal and gas) and hydro projects, long-term power is procured through a
negotiated route or pursuant to a competitive bidding route. Power procurement in the
Indian market is increasingly being done through the competitive bidding route. The
Ministry of Power, by a notification in January 2011, has informed state governments
and distribution companies to procure power under the competitive bidding route
(except mandatory competitive bidding for hydro-power projects has been postponed)
using either of two prescribed modes: Case 1 or Case 2. Under Case 1 bidding, a
distribution licensee invites bids to procure a specified quantum of power (without
specifying the location, technology or fuel of the source of supply). In Case 2 bidding, the
distribution licensee invites bids for setting up projects on the basis of the lowest tariff,
and also specifies the fuel and location of the project (which is typically arranged by the
distribution licensees or state governments). For renewable energy projects, long-term
contracts are entered into with state utilities under specific state policies at preferential
tariff or through competitive bidding depending on the state or central policy.
Other than long-term PPAs, there has been a gradual build up in the volume
of short-term transactions. The CERC, through its Power Market Regulations 2010,
seeks to promote and regulate interstate electricity transactions in various contracts,
including bilateral contracts and those transacted through traders and exchanges. The
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Power Market Regulations aim to transform the role of power exchange from acting as
price signal for investments to the dual role of providing price signal as well as acting as
risk transfer platform. The market is bifurcated into over-the-counter (‘OTC’) markets
and exchange-traded markets. The Power Market Regulations envisage:
a various types of OTC contracts (back-to-back deals, deals with open position,
aggregation of sellers or buyers, spot contracts, derivatives, etc.);
b contracts traded on exchanges (spot, day-ahead, term-ahead, financial derivatives
on exchanges, etc.);
c capacity contracts, ancillary services market contracts and renewable energy
certificates (‘RECs’); and
d derivative contracts, ancillary services contracts.
Capacity contracts, although mentioned in the Power Market Regulations, are not yet
permitted to be transacted and will be developed in due course, keeping in view the
demand–supply gap. Further, long-term delivery-based OTC contracts are not proposed
to be controlled by the power market regulations. These are mentioned in the market
oversight section only for the purpose of reporting by electricity traders. Currently, only
spot trading in power is allowed by CERC on both the Indian Energy Exchange and the
Power Exchange India Limited.
In 2010 the CERC also issued regulations on introducing RECs. The REC is
a market-based policy instrument created to increase and promote renewable energy
capacity. Under the REC mechanism, renewable energy producers get tradeable
generation-based certificates if they do not opt for the preferential feed-in tariff offered
by the state distribution utilities. These RECs can be bought by certain obligated entities
(such as electricity distribution licensees and captive power consumers) to fulfil their
renewable purchase obligations (‘RPOs’).
The Indian gas markets are relatively small but expanding rapidly. In comparison
with electricity market, the gas market has much to evolve in terms of outreach in most
states and pricing issues. As per NELP, the domestic market shall have the first choice on
the utilisation of natural gas discovered and produced domestically.
The MoPNG has been regulating the allocation and pricing of gas produced by
ONGC and OIL (both state-owned companies) by issuing administrative orders from
time to time. The gas produced by joint ventures and by NELP operators is governed
by the respective PSC between the government and the producers. Contractors are
entitled to market gas in the domestic market on an arms’-length basis subject to the
government’s Gas Utilisation Policy.
The price of liquefied natural gas (‘LNG’) is generally linked to the price of crude
oil, especially for long-term supplies. It is purchased on term contracts or on a spot
basis on mutually agreeable commercial terms. The resultant price of regasified LNG is
typically significantly higher than the price of domestic gas, including from the NELP
fields. The prices of such supplies being linked to crude are inherently volatile. The
MoPNG had proposed pooling of LNG and natural gas prices, which the Ministry of
Power rejected.
The Indian Multi Commodity Exchange undertakes online trading of natural
gas since June 2006. A memorandum of understanding was signed between GAIL and
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Natural Commodity and Derivatives Exchange for the joint working of developing a spot
market for natural gas, but this arrangement for spot market trading is yet to materialise.
Vi
RENEWABLE ENERGY AND CONSERVATION
i
Development of renewable energy
The regulatory environment increasingly seeks to incentivise renewable energy, with
favourable tariff regimes established by SERCs. The Electricity Act, the National Electricity
Policy and the Tariff Policy encourage private sector participation in renewable energy
through various measures such as providing for feed-in tariffs and fixing minimum RPOs
for distribution utilities and captive power users. In addition, a renewable energy project
developer is also entitled to receive RECs if they do not opt for preferential feed-in tariffs,
for which there is increasing demand.
Several states have put in place specific policies to promote renewable energy
development; however, incentives and policies are not always consistent between states
often developers shop around based on the policy that best suits their financial model and
operational expertise. Some states have established nodal agencies to promote renewable
energy generation and to assist developers with project development. 6 These agencies are
responsible for implementing measures and providing incentives under the respective
state policies.
Some of the key incentives (which may vary depending on energy source type)
offered to renewable energy power producers include:
a accelerated depreciation schemes;
b excise duty exemptions or concessions as well as reduced customs duty on
renewable energy equipment;
c
d
low-interest loans from Indian Renewable Energy Development Agency; and
loan guarantees from various government as well as multilateral financial
institutions.
Sharing of CDM benefits (established under the Kyoto Protocol of the United Nations
Framework Convention on Climate Change), a significant financial incentive for
developing renewable energy projects, is fairly similar across states with most state
regulators adopting the CERC regulations that provide for sharing of CDM benefits on
a gross basis, starting from 100 per cent to the account of the developer in the first year
and reducing by 10 per cent every year until sharing stands at 50:50 between developer
and consumer (usually a state-owned distribution utility) by the sixth year.
6 Tamil Nadu Energy Development Agency (TEDA), Maharashtra Energy Development Agency
(MEDA), Gujarat Energy Development Agency (GEDA), Karnataka Renewable Energy
Development Limited (KREDL), Rajasthan Renewable Energy Corporation Limited (RREC).
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Onshore and offshore wind power
Wind energy is the fastest-growing form of renewable energy in India. It accounts for
nearly 70 per cent of the installed renewable capacity in India. Wind power policies vary
from state to state, but there are non-binding guidelines from the Renewable Energy
Ministry on setting up wind projects. In a general comparison, wind power policies
in certain states are rated more highly for the incentives they provide and availability
of a (more or less) single-window clearance mechanism. Until recently, wind-power
projects could claim either accelerated depreciation of up to 80 per cent or generation
based incentives (i.e., a monetary entitlement per unit of electricity fed into the grid).
In a recent development, the 80 per cent accelerated depreciation has been done away
with for wind farms developed after 31 March 2012, and now only the standard 15
per cent accelerated depreciation can be claimed. Even the generation based incentives
scheme expired on 31 March 2012. However, there is speculation that generation based
incentives may be extended.
Development of offshore wind energy is also being considered in India. The
Renewable Energy Ministry recently constituted a committee to steer offshore wind
power development in India (especially in Tamil Nadu, Maharashtra and Gujarat).
The committee is entrusted with creating an institutional mechanism for integration of
offshore wind power with established uses of the sea; evaluation of the potential partners
(private or public sector) for setting up of pilot projects and evaluation of public private
partnership for off-shore projects.
Solar energy
Solar plants can be set up under the Renewable Energy Ministry’s Jawaharlal Nehru
National Solar Mission (‘the JNNSM’) as well as under state policies (particularly
favourable are policies in Gujarat and Rajasthan). The JNNSM was set up in 2010.
It aims at the commissioning of 20GW grid-connected solar power by 2022 and the
development and deployment of solar energy technologies in the country to achieve
parity with grid power tariff by 2022. While tariffs for purchase of solar power currently
offered under the JNNSM are applicable only its first phase (i.e., until 2013), the tariffs
announced by the certain state governments (e.g., Rajasthan and Gujarat) are more
attractive (although there has been some downward revision in 2012). Certain states
have also come up with competitive bidding for setting up solar projects.
While the number of solar developers opting for RECs is currently negligible,
with falling prices for solar plant equipment, a greater number of solar power project
developers may opt for the REC mechanism in the future.
Accelerated depreciation of 80 per cent continues to be allowed for solar power
projects. The Renewable Energy Ministry also has a generation-based incentive scheme
to support small grid solar power projects connected to the distribution grid (less than
33kV) to the state utilities. This benefit is only for selected projects and the scheme is not
open to accept new project proposals currently.
Bio-power and waste-to-energy projects
The Renewable Energy Ministry has proposed to launch the National Bio-Energy
Mission (on the lines of JNNSM) to boost power generation from biomass by facilitating
capital investments. Currently, the Renewable Energy Ministry provides for various fiscal
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and financial incentives. Capital subsidies are available under the Renewable Energy
Ministry’s central financial assistance scheme for biomass power and bagasse cogeneration
projects. Further, an accelerated depreciation of 80 per cent is also available on relevant
capital goods.
In the context of municipal waste-to-energy projects specifically, there is significant
scope in Indian cities for business; however, several challenges are being faced by ongoing
projects. There is opposition on account of environment and health hazards for the
communities living in proximity to these projects. As a protective measure, stringent
regulations allow use of only those technologies that are duly approved by the Central
Pollution Control Board. Another significant concern for waste to energy projects is the
general unwillingness of banks to advance more than 55 to 60 per cent of debt toward
the overall project cost requiring a higher proportion of equity infusion. Under existing
Renewable Energy Tariff Regulations, equity infusion in excess of 30 per cent is treated
as normative loan, which in turn limits the return on equity on only 30 per cent of the
equity.
ii Energy efficiency and conservation
To institutionalise energy conservation efforts, the Energy Conservation Act 2001 was
enacted and the Bureau of Energy Efficiency (‘the BEE’) was established under the
Ministry of Power in 2002. Periodic energy audits have been made compulsory for
power-intensive industries under the Energy Conservation Act. The BEE has initiated
numerous energy efficiency initiatives including the launch of Energy Conservation
Building Code for large new commercial buildings; an energy-labelling scheme for
appliances; the initiation of process for the development of energy consumption norms
for industrial sub-sectors; and an annual examination to certify energy auditors and
energy managers.
The National Electricity Policy affords high priority to energy conservation and
demand-side management through the BEE. In order to reduce the requirements for
capacity addition, the National Electricity Policy promotes the reduction of the difference
between electrical power demand during peak periods and off-peak periods with suitable
load management techniques that are conducive to load management objectives.
To further enhance efficiency in thermal power projects, CERC tariff regulations
provide for operational norms such as reduction in heat rate for existing bigger units,
linking of allowable heat rate to design heat rate, tightening of working capital norms,
and norms on reduction in secondary fuel oil consumption.
iii Technological developments
The National Electricity Policy envisages special efforts being made for research,
development demonstration and commercialisation of non-conventional energy
systems. Further, it envisages the gradual introduction of efficient technologies (such as
super-critical technology and integrated gasification combustion cycle) for generation
of electricity. It also requires cost-effective technologies to be developed for high-voltage
power flows over long distances with minimum possible transmission losses.
In 2010, the Ministry of Power established the Smart Grid Task Force to
coordinate smartgrid activities in India and it also created the India Smart Grid Forum
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(a consortium of public and private stakeholders) to accelerate the development of
smartgrid technologies. According to media reports, the Ministry of Power is in the
process of finalising and implementing smartgrid technology-related projects on a pilot
basis. These pilot projects will focus on areas such as integration of renewable energy
sources with the grid, reduction of aggregate technical and commercial losses and peak
load management.
VIi
THE YEAR IN REVIEW
The past year has been significant in terms of the government as well as state governments
prioritising renewable energy and enhancing competitiveness. On account of the new
CERC regulations for interstate transmission charges, wheeling power from large
projects to customers across longer distances is expected to become cheaper and is also
expected to bolster spot market trading. The Ministry of Power’s direction to the CERC
to draft regulations to take bulk consumers outside the purview of regulated tariff in a
distribution licensee’s area could be a significant move in terms of increasing competition
and efficiency.
In the context of thermal energy, despite the ongoing uncertainty over assured
supplies of coal, coal-based thermal power projects remain the mainstay of the Indian
energy sector accounting for well over half of India’s annual generation of electricity. In
order to address existing uncertainty over the coal supply, the Ministry of Coal directed
Coal India Limited (‘CIL’) and its subsidiaries to enter into fuel supply agreements by
31 March 2012 (for projects commissioned after 31 March 2009 and those scheduled to
be commissioned by 31 March 2015). CIL, however, did not adhere to these directions.
Consequently, a decree was issued by the President of India on 3 April 2012 directing CIL
to give effect to the Ministry of Coal’s directions. While the legality of the presidential
decree may be questionable, such an action by the government does display its approach
toward energy issues.
On the oil and gas front, with the aim of overcoming problems such as availability
of gas, access (due to unidirectional flow) and need for specific gas type, the MoPNG
recently approved guidelines for gas-swapping transactions.
The PNGRB’s recent determination (in April 2012) of network tariff and
compression charges payable for use of CGD networks in Delhi has created a flurry, due
to significant reduction from the provisional tariff and retrospective application of the
recent tariff determination from 2008 (i.e., from when the CGD tariff regulations were
notified).
The MoPNG has been in the process of preparing the policy for allowing bidding
on shale gas projects and is expected to announce it by early 2013, which will be followed
by the first round of bidding. As in the United States, shale gas may hold the potential of
enhancing gas availability in India, reducing the reliance on imports.
Media reports suggest that the MoPNG is likely to offer the 10th round of
exploration blocks under the NELP in 2012.
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VIIi CONCLUSIONS and OUTLOOK
Major problems that affected the Indian energy sector in the early 1990s (such as the
lack of independent regulators and the lack of transparency in tariff determination) have
now been addressed. Several facets of the energy sector in India continue to evolve in
terms of policies and incentives. Private players are being increasingly incentivised in
the electricity as well as the oil and gas markets. Further, open access to transmission
and distribution facilities, as well as common carriage in pipelines, has greatly enhanced
competition. Sudden changes in policy measures and incentives have at times dampened
investor confidence (a recent example is the reduction of the 80 per cent accelerated
depreciation allowed to wind-power generators). On the other hand, the JNNSM and the
proposed Nation Bio-energy Mission are programmes that are poised to greatly enhance
renewable energy output, and set the pace for more ambitious targets for renewable
energy. Furthermore, media reports suggest that the government has been contemplating
liberalising FDI in nuclear energy. While, realistically, that may be some time away, such
a move could be a game changer in the energy market, given that fossil fuel availability
has been predicted to become more unpredictable in times to come.
Overall, the energy sector is moving towards a regime that seeks to enable
investment, improve market efficiency and competitiveness, and enhance energy supply
to meet India’s growth requirements.
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Chapter 11
Indonesia
Pudji W Purbo 1
I
OVERVIEW
To secure the domestic energy supply and to support sustainable development the
government has enacted a National Energy Policy as a guideline for the management of
national energy. Through Presidential Regulation No. 5 of 2006, the government sets
out the target and purpose of the National Energy Policy, and policy measures to achieve
the target. Under Presidential Regulation No. 5 of 2006, the Minister of Energy and
Mineral Resources (‘the MEMR’) was tasked with preparing and issuing a blueprint for
the management of national energy. The current blueprint, supported by Law No. 30
of 2007 regarding energy, covers from 2008 to 2027 and contains policies on securing
domestic energy supply, public service obligation and management of energy resources
and its use over an archipelagic area spanning more than 5,000 kilometres (around 3,200
miles) 2 with a yearly population growth rate of above 1 per cent for the past five years. 3
i Policy in the electricity sector
The development of the domestic modern energy sector, initiated almost three decades
ago, commenced with the 1985 Electricity Law, with the state-owned company PT PLN
as the sole supplier of electricity. PT PLN, however, was unable to cater for the increase in
electricity demand that took place; in 1992, therefore, the government, allowed private
parties to enter the power generation business activities. The issuance of Presidential
Decree No. 37 of 1992 opened the way for large-scale power generation utilities, both
through government-planned projects as well as private participation.
1 Pudji W Purbo is a partner at Makarim & Taira S.
2 www.indo.com/indonesia/archipelago.html.
3 www.indexmundi.com/g/g.aspx?c=id&v=24.
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When the Asian financial crisis hit in the late 1990s, large-scale power generation
utilities were affected. Projects were abandoned, and some renegotiated to a much lower
offtake price; overall, investor confidence was significantly lost, but PT PLN was in no
position to independently fund the much-needed additional capacity.
In 2002 the government introduced reforms largely through the enactment of
Law No. 20 of 2002 on Electricity (‘the 2002 Electricity Law’). However, the Indonesian
Constitutional Court deemed the 2002 Electricity Law to be unconstitutional since it
considered electricity a social necessity and thus its delivery should remain exclusively
with the state, through a state-owned agency. As such, the court re-enacted the 1985 Law.
Investment stalled in the electricity sector from the start of the 1997 Asian
financial crisis until 2005, when the government enacted Presidential Regulation No.
67 of 2005, which allowed public-private partnerships. Since the enactment of this
regulation, a list of independent power producer (‘IPP’) projects open for private tender
was made available.
Various regulations were enacted to support and give a legal basis for private
investment confidence, to urge diversification of energy for power generation to non-oil
fuel and to increase private investment in the power generation business.
As a replacement for the 2002 Electricity Law, in September 2009 the Indonesian
government enacted a new electricity law, Electricity Law No. 30 of 2009 (‘the 2009
Electricity Law’) in order to strengthen the regulatory framework and provide a role for
the regional governments to issue licences and determine electricity tariffs.
ii Policy in the oil and gas sector
The 2001 Oil and Gas Law marks the liberalisation of the oil and gas sector in Indonesia.
The state-owned oil and gas company, PT Pertamina, was stripped of its multi-function
role as a regulator, supervisor and manager of oil and gas business activity. PT Pertamina
is now only a market participant, without any supervisory and managerial function for
other upstream oil and gas companies. Based on the 2001 Oil and Gas Law, upstream oil
and gas is controlled by the government through production-sharing contracts between
the executing agent, the Oil and Gas Upstream Regulator and Implementing Agency
(‘BPMigas’), and the business entity. The downstream activity is controlled by the
relevant regulatory agency (‘BPH Migas’).
On the production and opportunity side the trend has now shifted from the
declining production of oil towards gas production, in particular to serve the domestic
power generators. With declining production and increased consumption of oil, Indonesia
became a net importer of oil in 2004. The results of government efforts to open new acreage
and provide incentives are yet to be seen. Recent regulation on cost recovery and tax on
oil and gas production has created investor insecurity and questions on contract sanctity.
iii Policy in the mining sector
Mining and coal is regulated under the Law of Mineral and Coal Mining No. 4 of 2009
(‘the 2009 Mining Law’), which introduced a permit-based concession from the more
favoured agreement-based concession (contracts of work). Major regulatory development
introduced tender process for new acreage, domestic market obligations, mandatory
in‐country processing and restriction on use of mining services by concession holders.
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Control of the production and domestic market obligations, including a higher
percentage of divestment requirement, have affected the interest of investors wishing
to enter the lucrative Indonesian mining industry. The slow progress of the required
implementing regulations to enable implementation of the 2009 Mining Law creates
legal uncertainties for existing but also for prospective investors in the mining sector.
II
REGULATION
i The regulators
The energy sector, encompassing oil and gas, coal and renewable energy, is regulated
and supervised by the central government through the MEMR and its directorates
and agency bodies. Regional governments (the provinces and regents within each
province) are granted decentralised authority to issue certain licences and permits, and
deconcentration of authority from the MEMR for certain supervisory tasks. For the
electricity sector, the directorates of the MEMR regulating electricity activities are the
Directorate General of Electricity and Energy Utilisation and the Directorate General of
Renewable Energy and Energy Conservation.
While PT PLN is responsible for the majority of Indonesia’s electricity generation
and has exclusive powers in relation to transmission, distribution and supply of electricity
to the public, PT PLN is itself regulated and supervised by the MEMR and the Ministry
of State-Owned Enterprises (‘MSOE’).
The MEMR is responsible for developing the electricity master plan (‘the
RUKN’). The RUKN, inter alia, sets out estimates of power demand and supply for 10-
year periods. The RUKN also provides the approach of the government to the utilisation
of new and renewable energy resources. The current RUKN was issued in 2008 for the
period from 2008 to 2027. The RUKN is reviewed annually, and if need be, adjusted
accordingly.
Based on the RUKN, as mandated by the current law and regulation, PT PLN
prepares the national electrical generation plan (‘the RUPTL’), which is approved by the
MEMR. The RUPTL is an official 10-year power development plan containing demand
forecasts, future expansion plans, kWh production, fuel requirements and indications
on projects to be developed by PT PLN and IPP investors. The RUPTL is also reviewed
annually. The current approved RUPTL is for 2011–2020.
The 2009 Electricity Law also requires that regional governments prepare regional
general plans of electricity (‘RUKDs’) based on the RUKN for each region.
The oil and gas sector falls under the authority of the Directorate General of
Oil and Gas, a directorate general in the MEMR. The management of upstream oil
and gas production by contractors is managed and supervised by BPMigas. BPMigas is
the non-profit state-owned legal entity, which controls these activities on behalf of the
government through production-sharing contracts. The management and supervisory
roles of BPMigas are:
a advising the MEMR on the preparation and offering of work areas and joint
cooperation contracts;
b acting on behalf of the government as a party to the joint cooperation contracts;
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c
d
e
f
g
assessing first plans of development of a given work area and submitting its
evaluation on the MEMR for approval;
approving other plans of development;
approving work plans and budgets;
reporting to the MEMR on implementation of joint cooperation contracts; and
approving seller of the state portion of petroleum and natural gas to the best
advantage for the governement.
Further stipulation on the scope of supervision of upstream oil and gas activities may
be conducted by the MEMR and the chairman of BPMigas. The chairman of BPMigas
is appointed by the President of the Republic of Indonesia after consultation with the
parliament and is responsible to the President.
The regulatory body for oil and gas downstream activity, BPH Migas, regulates
and supervises the availability and distribution of oil-based fuel and natural gas through
pipelines, to ensure availability and distribution throughout all areas of Indonesia.
BPH Migas is also responsible for the supervision of fuel distribution and
transportation of gas through pipelines operated by Indonesian companies. Its supervisory
and distribution role regarding fuel oil encompasses supply and distribution, allocation
of reserves, market share and trading volumes and settling disputes. In the transportation
of gas, BPH Migas is responsible for the development of transmission segments and
distribution network areas, determination of natural gas pipeline transmission tariffs and
prices, market share of transportation and distribution, and settling disputes.
The BPH Migas chairman and its eight members are appointed by the President
after consultation with the parliament, and they are responsible to the President.
The primary source of law for oil and gas is Law 22 of 2001 on Oil and Gas (‘the
2001 Oil and Gas Law’).
Mineral and coal mining activities, under the authority and supervision of the
MEMR and the Directorate General of Minerals and Coal, are governed by the 2009
Mining Law. The 2009 Mining Law replaces the Mining Law No. 11 of 1967, under
which existing concessions under contract of work and coal contract of work were based.
The 2009 Mining Law introduced a significant change to the previous mining
legal framework. Contractual-based concessions, in the form of contracts of work, are
now no longer available for mining concessions. Contracts of work for foreign investors
and mining rights, in the form of ‘Kuasa Pertambangan’ for Indonesian investors, have
been replaced by a licensing system, ‘Ijin Usaha Pertambangan’. The implementing
regulations for the 2009 Mining Law are in the form of Government Regulations and
further decrees and regulations issued by the MEMR and the Directorate General of
Minerals and Coal, or regional regulations where regional governments were given
authorisation under the 2009 Mining Law.
Under the 2009 Mining Law, mining areas are designated by the central
government (the MEMR) as open for mining. Mining areas are categorised as commercial
mining areas for large-scale mining, state reserved areas for national strategic interest,
and people’s mining areas, for small-scale local mining.
With the assistance of the regional governments, the MEMR carries out mapping
exercises and prepares maps of area open for mining. Maps may be updated every five
years, and the final map designated areas must be approved by the parliament.
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New licences for commercial mining areas are issued though competitive tender
procedures. The details of tender process are yet to be issued through MEMR regulations.
A mining licence is granted in two separate phases of mining activities: exploration phase
and production operation phases. Exploration licences may be issued by either a regional
government or the central government (if the area covers more than one province),
depending on the location of the proposed mine and its associated infrastructure. The
authority to issue production operation licences depends on the location of the mine
infrastructure and the environmental impact of the project.
Mining licences for state reserved areas are issued by the MEMR, regardless of the
coverage of the mining area.
The 2009 Mining Law and its implementing regulations grant the MEMR
authority to require mining licence holders to supply mineral and coal for domestic use
in consideration of domestic mineral and coal requirements, such as for the mineralprocessing
industry and for domestic direct utilisation (coal requirements for fuel and
coal requirements for raw materials for domestic processing industries). The MEMR
sets the floor price for domestic market obligation sales, which are based on minimum
prices for export. The MEMR is also authorised to set the mineral and coal sales reference
price. The MEMR, through the Directorate General of Minerals and Coal, is responsible
for setting the benchmarked price for coal and metallic minerals, while Governors and
Regents in the regional governements are responsible for setting the benchmarked price
for non-metallic minerals and rock.
The MEMR has a regulatory and supervisory role within the energy and mineral
sector, and this role is based on the laws governing energy, electricity, oil and gas, and
minerals, as well as other sectors falling under the MEMR’s authority. Regulatory and
supervisory tasks are disseminated through ministerial regulations, and director general
regulations, decrees, as well as guidelines and circular letters. Fiscal and tax matters on
the energy and mineral sector are under the authority of the Ministry of Finance, which,
in issuing regulations concerning energy and minerals, works in coordination with the
MEMR. The legislator, the People’s Representative Body, has rights to question the relevant
Ministry on the implementation of Laws within each Ministry’s respective authority.
Regional governments (provinces and regencies), as a matter of decentralisation,
are given certain authority within the energy sector to issue permits and licences. The
MEMR may also assign a supervisory role to regional governments in implementing
supervision in the mining sector.
ii Regulated activities
Electricity
Since the 2009 Electricity Law came into effect, PT PLN is no longer the holder of
an exclusive electricity authorisation from the central government to provide electricity
for public use, and so no longer has a monopoly to supply and distribute electricity to
end customers. Instead, the provision of electricity for public use may be carried out
by state‐owned companies (‘BUMN’), regional-owned companies (‘BUMD’), private
business entities, cooperatives and non‐governmental organisations.
The 2009 Electricity Law divides the electricity business into two categories:
a activities involved in supplying electrical power, such as:
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b
• electrical power generation (both for self-use and sale to an off-grid captive
consumer);
• electrical power transmission;
• electrical power distribution; and
• the sale of electrical power; and
Activities involved in electrical power support, such as:
• consulting activities;
• construction and installation of electrical power equipment;
• operation and maintenance of electrical power equipment; and
• development of electrical supporting equipment technology.
Private sector partnership is allowed through the IPP arrangements. The appointments
are usually conducted through a bidding process except for certain areas such as renewable
energy, mine-mouth, crisis, marginal gas or expansion projects. The structure itself will
be based on the power purchase agreement between the private entity and the seller to
provide and produce electric power and supply PT PLN as the buyer at an agreed price
for an agreed period of time.
Under the 2009 Electricity Law, there are two types of electricity licence for two
types of business:
a electricity business:
• electricity business licence (‘IUPTL’) for public use; and
• provision of electricity business licence for own use.
b electricity supporting businesses:
• electricity supporting services licence (‘IUJPTL’); and
• electricity supporting industry licence.
An IUPTL is granted by the Minister/governor/regent/mayor (depending on where the
business activity is located and the area coverage of the activity) to a BUMN, BUMD,
private business entity, cooperative or non-governmental organisation.
An IUPTL covers the following business activities:
a power generation;
b transmission;
c distribution; and/or
d sale of electricity.
The electricity business for public use may be carried out as an integrated activity to cover
all business activities, from construction and operation of a power plant, to transmission,
distribution and sale of electricity to end customers. The central government has authority
to grant IUPTLs to business entities where:
a the relevant business area crosses provinces;
b
c
the business entity is a BUMN; or
the business entity sells its power or leases its transmission line to a holder of an
IUPTL issued by the central government.
The 2009 Electricity Law does not specify the procedures for applying for an IUPTL;
implementing regulations have to be issued by the MEMR and the Directorate General
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of Electricity. Pending the issuance of implementing regulations, IUPTL applicants are
expected to follow the requirements under the 1985 Electricity Law, provided they do
not contradict the 2009 Electricity Law or any of its implementing regulations.
Oil and gas
New acreage for oil and gas are generally tendered and concessions are granted through
joint cooperation contracts with BPMigas (on behalf of the government). Field plans of
developments (which include proposed offtakers) are approved by BPMigas. In crude
oil and natural gas, the oil contractors are responsible for meeting the demand of crude
or natural gas for domestic consumption. Government Regulation No. 35 of 2004
(implementing the 2002 Oil and Gas Law) sets a maximum of 25 per cent of the oil and
gas contractor share of production of oil or natural gas for domestic needs.
Domestic gas sales price by contractors are negotiated among BPMigas, buyers
and individual contractors on a field-by-field basis, based on the economics of a particular
gas field development. Prior to the 2002 Oil and Gas Law, gas was sold to PT Pertamina
at a fixed price under a long-term gas supply agreement, who then sold the gas to the
end-users (mostly to PT PLN and the state gas company, PGN). In general, producers
can sell and negotiate directly with offtakers, however due to the government’s stake
involvement, the preference of the government is to sell to domestic users.
Non-integrated liquefied natural gas (‘LNG’) projects require negotiation of the
gas price between the producer and the LNG plant owner, to be then sold to end-users
after processing.
For the oil and gas downstream activities of processing, transportation, storage
and trading, separate licences are required if it is not integrated as one continuous
activity of the upstream oil and gas producing project. Unlike the ringfencing policy in
the upstream business, the downstream business allows one entity or company to hold
multiple licences.
All licence holders in downstream oil and gas activities must submit periodic
reports to the MEMR and or BPH Migas. The MEMR and BPH Migas regulate, control
and supervise the processing, storage, distribution and transportation of fuel oil and – to
some extent – the retail price for certain types of fuel oil.
Processing of gas is classified as a downstream business activity if intended as
a profit-making business and not as part of an upstream development. Approvals for
LNG and mini-LNG refineries have been granted to very few projects, partly due to the
government’s concerns about domestic gas supply demand.
Transportation of gas by pipelines via a transmission segment or a distribution
network area is permitted only with the approval of BPH Migas, with licences granted
for specific pipelines or commercial regions. A company with a transportation business
licence is required to prioritise use of transportation facilities owned by cooperatives,
small enterprises and national private enterprises when using land transportation; provide
an opportunity to other parties to share utilisation of its pipelines and other facilities
used for the transportation of gas; and comply with the master plan for a national gas
transmission and distribution network.
In line with the National Energy Policy, BPH Migas has the authority to
regulate, designate and supervise tariffs. An increase of capacity of facilities and means of
transportation is allowed after obtaining special permission.
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A company holding a storage licence is required to provide the opportunity to
other parties to share in its storage facilities; it can increase the capacity of its storage and
related facilities after obtaining permission from BPH Migas.
A wholesale trading licence allows the holder to operate a trading business to serve
certain consumers (e.g., large consumers). The MEMR, along with BPH Migas, may
determine the minimum capacity limit of a storage facility or facilities of a company. The
company may start its trading business after fulfilling the required minimum capacity. A
direct user who owns a seaport or receiving terminal may import fuel oil, gas and other
fuels, and process the output directly for its own use, but not for resale, after obtaining
specific approval from the MEMR.
Minerals and coal
As part of government policy to guarantee the supply for domestic demand, especially
for coal, the 2009 Mining Law and its implementing regulations create a framework
where the central government has the authority to control the production and export
of each mining product. Regional governments are also obliged to comply with the
production and export controls imposed by the central government. Mining companies
must comply with the domestic market obligation by selling to domestic consumers of
minerals or coal.
The Government Regulation on the Implementation of Mineral and Coal Mining
Business Activities provides a framework authorising the MEMR to set the coal sales
reference price. The benchmark price serves as the floor price for royalty payment to the
government.
iii Ownership and market access restrictions
Investment Law No. 25 of 2007 provides a one-stop investment framework for foreign
investors under the Indonesian Investment Coordinating Board (‘the BKPM’), which
includes centralisation of the issuance of permits, licences and facilities.
The primary regulation at which foreign investors have to first look before
entering into a particular activity in Indonesia is the Negative List. The Negative List
is a set of business activities that are closed or open with limitations to foreign direct
investments. The Negative List is updated periodically, the latest one having been issued
under Presidential Regulation No. 36 of 2010.
For investment in electricity, the Negative List generally sets the maximum
ownership of foreign shareholders to 95 per cent for foreign investment in the fields
of production, transmission and distribution of electricity and 90 per cent in entities
performing operation and maintenance services for geothermal energy; however, the
limitation varies depending on the specific business and sectors.
The Negative List does not restrict foreign direct ownership in companies holding
a mining licence, it allows 100 per cent foreign ownership, which is in line with the 2009
Mining Law.
The Investment Law applies only to companies operating in the downstream
sector. Foreign investment in the upstream oil and gas sector is by way of a branch of a
foreign company.
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Indonesia
Transfers of control and assignments
The 2009 Electricity Law and its implementing regulations do not specify the transfer of
control and assignments in the electricity industry. In general transfer of control will be
provided in the power purchase agreements, and usually with the approval of PT PLN.
Maximum foreign ownership as provided in the Negative List must also be observed in
the transfers of control, as well as the requirement under the Company Law.
In any foreign direct investment companies, transfer of control and assignments
will require processing through the BKPM and the Ministry of Law and Human Rights
(‘MLHR’). Recommendations by and reporting to the MEMR is also required for
mining companies wishing to transfer control.
An application for transfer of control is first submitted to the BKPM, accompanied
by a recommendation from the MEMR (for mining sector companies and downstream
oil and gas companies). After registration is approved the company submits the transfer
agreements and corporate documentation to the MLHR for the change of control. The
average time required to complete a transfer is between one and three months, depending
on the industry segment.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
The 1985 Electricity Law provided for a centralised system with state-owned electricity
company PT PLN holding exclusive power over the transmission, distribution and sale
of electricity. Private companies were allowed to generate electricity only, to be sold to
PT PLN.
After the Asian Financial crisis of the late 1990s, the government tried to liberalise
the electricity industry through the enactment of the 2002 Electricity Law, allowing
independent private producers to sell directly to consumers within a competitive area.
In parallel with the attempt to liberalise the electricity sector, the government also began
liberalisation and demonopolisation of the oil and gas sector with the promulgation of
the 2001 Oil and Gas Law. Both the 2001 Oil and Gas Law and the 2002 Electricity Law
were reviewed by the Constitutional Court.
When the 2002 Electricity Law was declared unconstitutional, the system reverted
back to the 1985 Electricity Law, pending the issuance of a new law on electricity.
Meanwhile, the 2001 Oil and Gas Law eventually passed the Constitutional Court review
except for a few provisions. Through the 2001 Oil and Gas Law, reform of the oil and gas
sector took place carving out a managerial role in oil and gas production and operation
from the state-owned oil and gas company, Pertamina, for a new agency, BPMigas; it
also demonopolised downstream oil and gas from Pertamina, allowing distribution,
transportation and transmission to private entities to be regulated by BPH Migas.
Along with the deregulation of the oil and gas sector, the government’s policy
in trying to adopt a mixed fuel policy for power generation was hampered by the
underdeveloped infrastructure for domestic natural gas distribution. To balance the
rise of the oil prices and the lack of infrastructure for domestic gas transportation,
and to support the government’s fast-track programme in the supply of electricity, the
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government turned to coal, requiring coal-mining companies to sell a percentage of their
production to domestic users (mostly power generators) through the introduction of the
2009 Mining Law and its implementing regulations.
Only in 2009 was the government able to introduce the new 2009 Electricity Law.
Under this Law, the electricity supply business in Indonesia is still controlled by the state,
but is conducted by the central and regional governments through PT PLN and regionally
owned entities. From having a single supplier, transmitter and distributor of electricity
under the 1985 Electricity Law, the 2009 Electricity Law transformed the system to allow
regional authorities to play a greater role in the electrification of remote regions. PT PLN
is now merely the holder of an IUPTL but has the first right of refusal for unserviced areas,
which, if not accepted, can be taken up by the private sector. If the private sector does not,
however, take up a business opportunity, the central government will instruct PT PLN to
supply the area. The regional authorities will not prepare an RUKD based on the RUKN.
ii Transmission/transportation and distribution access
While PT PLN still has priority right to conduct transmission and distribution and
retailing throughout Indonesia, as the sole owner of transmission and distribution assets,
it also remains the only business entity in charge of transmitting and distributing electric
power. The 2009 Electricity Law allows private participation in the supply of electricity
for public use; however, current private sector participation is still limited to the power
generation sector.
Transportation of gas by pipelines via a transmission segment or a distribution
network area is permitted only for specific pipelines or commercial regions with the
approval from the MEMR and BPH Migas. Licence holders are required to prioritise use
of transportation facilities owned by cooperatives, small enterprises and national private
enterprises when using land transportation, and provide an opportunity to other parties
to share utilisation of its pipelines and other facilities used for the transportation of gas.
Storage companies are required to allow the opportunity to other parties to share
their storage facilities, and share storage facilities in remote areas.
iii Rates
With the private participation limited to the power generation sectors and transmission
lines mostly owned by PT PLN (or its subsidiaries) there is no market for transmission
line tariffs.
iv Security and technology restrictions
In 2004 a Presidential Decree was issued detailing the protection of critical and strategic
infrastructure. The Coordinating Minister of Politics, Law and Security coordinates the
management for the protection of critical infrastructure with each relevant ministry under
which supervision such critical infrastructure falls. The MEMR identifies and provides
an updated list of infrastructures that are categorised as critical and strategic to the state.
The police force and, if needed, the armed forces, is tasked with the onfield execution of
protection in accordance with the standard procedure existing within the respective force.
As implementation of the Presidential Decree on Protection of Critical
Infrastructure, the national police prepared a guideline on the system for protection
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of critical infrastructure. In practice, coordination and cooperation between the
infrastructure manager and the police is still considered weak. Some vital systems of
infrastructure have not yet met the standard requirement for protection and the police
force deployment cannot meet the required level of personnel. Utilisation of modern
infrastructure protection devices is also minimal.
IV
ENERGY MARKETS
The National Energy Policy and the 2009 Electricity Law, the 2001 Oil and Gas Law and
the 2009 Mining Law provide for the tendering of energy business opportunities by the
MEMR. The bidding process is generally on a competitive basis through a transparent
process. After a preferred bidder is selected, PT PLN and the preferred bidder follow a
process involving, inter alia, negotiations of electricity tariffs and other terms, approval
of tariffs by the MEMR, issuance of business licences by the MEMR, completion of
financing, and EPC awarding followed by commercial operation commencement.
Direct appointment is permitted for certain expansion projects, in crisis situations and
for marginal gas and renewable energy projects.
Prices of electricity to end users are regulated based on the category of end user. Gas
sales prices are approved by the MEMR. There is no organised market for energy or gas.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Currently, the development of renewable energy is regulated by Presidential Decree No. 5
of 2006 regarding the National Energy Policy. This decree states that the contribution
of new and renewable energy in the 2025 national primary energy mix is estimated at
17 per cent, consisting of 5 per cent biofuel, 5 per cent geothermal power, biomass,
nuclear, hydro, and wind, and also liquefied coal at 2 per cent. The government will take
measures to add the capacity of micro-hydropower plants to 2.8GW by 2025, biomass
to 180MW by 2020, wind power to 0.97GW by 2025, solar to 0.87GW by 2024, and
nuclear power to 4.2GW by 2024. The total investment needed for this development
of new and renewable energy sources up to the year 2025 is projected at $13.1 billion. 4
Indonesia’s geothermal reserves contain approximately 40 per cent of the world’s
total geothermal reserve (29.2GW), spreading across 250 locations all over the Indonesian
Archipelago.
Of the potential reserves, about 15.9GW are estimated reserves and about 2.3GW
are proven, 12.8GW are probable and 823MW are possible reserves. 5 The sector remains
underdeveloped with only around 1.2GW capacity installed. 6
4 The National Energy Policy.
5 http://prokum.esdm.go.id/Publikasi/Statistik/Statistik%20Energi%20Baru%20Terbarukan.
pdf.
6 Id.
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High development risk and the large upfront capital have so far been the main
inhibitors to development by investors. With a development phase of up to 10 years
with commercial production and project financing only available at the end of the phase,
significant upfront equity contribution is required.
As an effort to reduce cost on oil fuel spending and to boost geothermal power
projects, the government now encourages private-sector participation in geothermal
power generation by offering the Second Fast-Track Programme for geothermal power
projects. In this programme there are 33 geothermal power projects allocated to
independent power producers and 11 allocated to PT PLN.
To help investors, the government has issued a regulation which caps the price
that PT PLN can pay at 9.7 cents per kWh.
For geothermal projects there are a number of tax incentives and facilities such as
investment credits, accelerated depreciation or amortisation rates, reduced tax rates on
dividends paid to non-residents and tax loss carry-forward for up to 10 years. Import
duty exemptions also apply, as well as exemption of VAT on import of capital goods
during construction.
Feed-in tariff systems have been endorsed by studies conducted by international
agencies.
ii Energy efficiency and conservation
Currently, the government is trying to change the paradigm of national energy
management, which was previously focused on the supply side to the demand side.
Energy management used to be based on the supply side where the government tried
to meet energy needs, regardless of the amount or costs, through management of fossil
energy sources. Fossil energy continued to be subsidised in order to meet energy needs,
but exploration and utilisation of alternative and renewable energy was not prioritised.
The use of energy by the household, industrial, commercial and transportation sectors
was very wasteful due to the lack of emphasis on energy efficiency.
The government now manages energy demand by ensuring that the needs and
use of energy in the household, industrial, commercial and transportation sector are
increasingly efficient. This can take place by energy users adopting more energy-efficient
behaviour and starting to use more efficient technologies. In addition, the supply and
use of renewable energy is maximised and if necessary, subsidised. Fossil energy is only
used as a counterweight and sources of untapped fossil energy can be used as a reserve
for future generations.
In an effort to develop the area of energy efficiency and conservation in Indonesia
various agencies from developed countries are lending support to the system.
iii Technological developments
The Clean Energy Initiative by the government is an integrated effort to achieve energy
efficiency and reduce greenhouse gas emission from fossil fuel burning. The Clean
Energy Initiative, as part of Indonesia’s participation in mitigating climate change,
by the MEMR is not only aimed at reducing national emissions but also at achieving
sustainable national energy security.
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With the help of the Danish government, the Indonesian government established
the Energy Efficiency and Conservation Clearing House Indonesia (‘EECCHI’), a service
facility under the MEMR, which aims to promote and enhance energy conservation and
energy efficiency in Indonesia.
The EECCHI systematically collects and processes information about energy
efficiency and conservation in Indonesia. It also provides information services in the
field of energy efficiency and conservation in the household, industrial, commercial and
transportation sectors. The EECCHI also plays an active role in raising public awareness
to implement energy conservation and energy efficiency through various outreach
programmes, training, workshops, conferences and seminars.
The EECCHI was originally an initiative of the Directorate of New Renewable
Energy and Energy Conservation, which in August 2010 became the Directorate General
of New Renewable Energy and Energy Conservation, under the MEMR.
The USAID Indonesia Clean Energy Development (ICED) project is also
working with Indonesian government agencies (central, provincial, and local), PT PLN,
non‐governmental organisations, communities, universities and the private sector to
provide support for Indonesia’s clean energy objectives. The project will support the
Director General for Renewable Energy and Energy Conservation in the MEMR to
improve energy sector policies and coordination; work with three provinces, local
governments, and PT PLN in Sumatra to increase the development of clean energy
projects; and increase institutional capacity and public outreach of government and
other stakeholders for clean energy.
VI
THE YEAR IN REVIEW
Regulations affecting energy business and energy fuel have been issued to implement
the 2003–2020 National Energy Policy, the Energy Blueprint 2006–2025 and the 2009
Electricity Law.
In the energy sector, the government has issued Presidential Decree No. 4 of 2010
as a legal base for the 10GW second-phase acceleration programme. This programme is
aimed at increasing electricity supply to support increasing demands and diversifying
power stations energy sources.
Presidential Decree No. 4 of 2010 states that PT PLN must carry out an
accelerated electricity development programme by harnessing renewable energy, coal,
and gas. This decree forms a legal base for PT PLN to carry out an accelerated electricity
development programme using domestic environmentally friendly energy.
The Presidential Decree also regulates that funding for the accelerated electricity
development programme is sourced from the state budget, PT PLN, and other legal
forms of funding regulated under prevailing laws. In carrying out this programme,
PT PLN is authorised to cooperate with IPP through an electricity purchase programme.
The 10GW acceleration programme is an important milestone in preparing future
energy reserves. During the second phase of this acceleration program, PT PLN plans to
build a total of 6.4GW-worth of power plants, requiring a total investment of $7.605
million. IPPs will build a total of 4.2GW-worth of power plants, requiring investment
of $8.450 million.
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The accelerated electricity development programme consists of several different
types of power plant: 4.3GW steam power, 3.6GW geothermal power, 1.6GW steam gas
power, and 1.2GW micro hydro power.
The total number of power plants currently being developed by PT PLN and
IPPs is equivalent to 29.4GW. The 10GW second-phase acceleration programme should
continue the 10GW first-phase programme so it can cope with an average annual
electricity demand growth of around 7 per cent.
Further, Presidential Regulation No. 13 of 2010 provides support for publicprivate
participation by establishing PT Sarana Multi Infrastruktur and its subsidiary PT
Infrastruktur Financing, to play the role of a fund to support infrastructure financing.
The government also supported the electricity industry by establishing PT Penjaminan
Infrastruktur Indonesia to provide guarantees for infrastructure projects, including in
the electricity sector.
During the past 12 months regulations issued by the MEMR have been geared
to support the use of gas and geothermal energy as sources of power generation. These
regulations cover the price of electricity from geothermal power plants, allocation of gas
for power plants, and supporting geothermal power plant developments based on the
second acceleration programme in power plant development.
VII
CONCLUSIONS and OUTLOOK
The 2006–2025 National Energy Policy, the Energy Blueprint 2008–2027, and the
laws governing electricity, oil and gas and mining will need to have detailed guidelines
and action plans – such as strict energy performance standards and financial incentive
schemes – to ensure successful implementation.
A further step towards ensuring a secure and sustainable energy sector would
be for Indonesia to continue its policy of reducing fossil fuel subsidies and shift them
towards green subsidies. The government’s effort to shift its energy policy is being
implemented through policies that support private investors in the energy sectors
and working together on a bilateral level as well as with private agencies to prepare a
sustainable working environment. Securing domestic supply of fuel for power generation
and providing a mechanism for risk allocations for investment show a trend towards
supporting the market in terms of legal framework.
Although the government has the necessary ministries and agencies in place for
effective energy policymaking and implementation, the coordination, decision making
and overlapping or unclear division of responsibilities among these institutions remain
serious issues. Complication also stems from the decentralisation of some administration
to the regional governments.
Delays on progress in projects already in the pipeline may occur due to the 2014
Presidential Election.
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Chapter 12
Italy
Simone Monesi 1
I
OVERVIEW
Italian gross consumption of electricity in 2010 was 346,223GWh, of which 12.9 per
cent was imported. 2 The market demanded an average of 39.5GW of gross power (ranging
from an average minimum of 22GW during night-time hours to 52GW during daytime
hours). The historical spot peak power demand was recorded in 2007 (in coincidence
with the peak of the economic cycle) equal to 56.82GW.
The aggregate maximum net installed capacity as at 31 December 2010 was
106,938MW.
In 2010 the main generation market players were ENEL (27.9 per cent of net
generation), Edison (11 per cent) ENI (10 per cent) E.On (5.7 per cent) and Edipower
(5.5 per cent).
In 2010 67.2 per cent of the demand was met by conventional power plants
burning fossil fuels imported to a very large extent from abroad; 20.6 per cent of the
demand came from renewable sources (hydro, geothermal, wind and photovoltaic
(‘PV’)) and the balance through electricity imports.
The nuclear programme that contemplated the building of eight new nuclear
power plants was abandoned in 2011 in consequence of a popular vote in the aftermath
of the Fukushima accident.
Natural gas accounted for 66.2 per cent of the total conventional fuel mix, coal
for 17.2 per cent and oil products for 4.3 per cent. Other fuels (including biomass,
waste and orimulsion) accounted for the balance. A massive shift towards natural gas has
occurred only in recent years (in 1994 oil fuels accounted for 94 per cent of the fuel mix).
1 Simone Monesi is a partner at Latham & Watkins LLP.
2 Terna, ‘Statistical Data on electricity in Italy, Synthesis 2010’, English version available at www.
terna.it/LinkClick.aspx?fileticket=2KFIU95%2bXTw%3d&tabid=811.
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Italy is the fourth importer of natural gas in the world, such imports being
sourced mostly from Algeria and Russia (and to a much lower extent from Libya, the
Netherlands, Qatar and Norway).
Transportation of gas take place through five pipelines connecting the Italian gas
transportation network with the Netherlands, Algeria, Russia, Libya and Norway, and
two regasifiers located in Panigaglia and Porto Tolle. Projects for the construction of
further five regasifers have been approved (while one was recently abandoned by British
Gas in Brindisi) but are facing considerable local opposition. Seven additional projects
are being considered.
The high-voltage (‘HV’) and ultra-high-voltage (‘UHV’) electricity transmission
grid is mostly owned and operated under a concession regime by Terna SpA, a publicly
listed company in which Cassa Depositi e Prestiti SpA (the Italian state investment arm)
holds a 29.85 relative majority stake. Terna is also responsible for dispatch.
The medium-voltage (‘MV’) and low-voltage (‘LV’) distribution grid is operated
by 144 (in 2010) distribution service operators (‘DSOs’) under a concession regime.
In 2010 Enel Distribuzione SpA accounted for 86.3 per cent of volume distributed,
followed by A2A Reti Elettriche (4.0 per cent), Acea Distribuzione (3.4 per cent) and
Aem Torino Distribuzione (1.3 per cent). All other DSOs have marginal market shares. 3
The national and regional gas transportation grid is managed under a concession
regime by 10 participants, the most important being SNAM Rete Gas, which controls
31,680 kilometres out of 33,768 kilometres of the grid, followed by the Edison group,
which controls 1,414 kilometres of the grid. 4
There are 10 national gas storage sites of which eight are managed by Stogit SpA
(part of the ENI group) and two are managed by Edison Stoccaggio. 5
At the end of 2010 there were about 250 gas DSOs. The ENI group was the
market leader with a 22.9 per cent market share in terms of volume.
Both the electricity and (downstream) gas markets are fully liberalised.
Retail customers and small business may opt between free market contracts and
‘protected categories service’. Both electricity and gas are traded on exchanges organised
and managed by Gestore dei Mercati Energetici SpA (‘GME’). Trading on exchanges is
carried out by generators, producers or importers, Acquirente Unico SpA (a single buyer,
procuring energy for resale through the distributors to protected categories), energy and
gas wholesalers, and gas shippers. Bilateral contracts may be entered into by all market
participants.
3 Autorità per l’energia elettrica e il gas (‘the AEEG’) ‘Relazione annuale alla commissione europea
sullo stato dei servizi e sulla regolazione dei settori dell’energia elettrica e del gas’, 31 July 2011;
available at www.autorita.energia.it/allegati/relaz_ann/11/Annual%20Report%202011%20
IT.pdf.
4 Id.
5 Id.
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II
REGULATION
i
The regulators
The energy market is regulated by the Energy and Gas Regulatory Authority, the AEEG,
an independent authority led by five commissioners appointed by the government with
the approval of a two-thirds majority of the competent parliamentary commissions. The
AEEG is responsible for, inter alia, overseeing access of market operators to the gas and
electricity grids and storage facilities, setting tariffs for access to the gas and electricity
grids, promotion of fair competitive practices, protecting consumers’ interest, promoting
market transparency and energy efficiency. The AEEG may issue regulations that apply
to market operators, and orders and decisions affect single operators. The main sources
of regulation in the energy market are state laws, regional laws and administrative
regulations issued by the AEEG.
ii Regulated activities
The electricity and gas markets have both been liberalised in furtherance of the objectives
set by the EU liberalisation directives enacted at the end of the 1990s.
In the electricity market, no licence is generally required to carry out generation,
import, export, purchase, supply and metering businesses. The operation of the
distribution grid is carried out by DSOs under a state concession regime. The transmission
grid is a natural monopoly mostly owned and operated under a concession regime by
Terna SpA, a publicly listed company
In the gas market, no licence is generally required for production, import, and
sales of natural gas. Storage, transport and distribution activities are operated under a
concession regime.
The development and construction of new facilities (e.g., transmission lines,
power plants and gas storage facilities) require permits mandated by state and regional
legislation to ensure compliance with, inter alia, health and safety standards, environment
protection and compatibility with existing infrastructure.
The process for obtaining such approvals is regulated by a combination of
state and regional legislation and depends on the nature and location of the facility to
be realised and of the permits required. The process is most often led by the regions
(or, depending on regional legislation, further subdivisions delegated by the regions,
for example, provinces), which coordinate the process involving all the agencies and
authorities whose consent or opinion is required to finalise the permission process.
iii Ownership and market access restrictions
There are no restrictions on ownership of new and existing assets or service providers,
other than – in relation to mergers and acquisitions – the instructions that the antitrust
authorities may require the parties to comply with for antitrust clearance.
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Transfers of control and assignments
A law decree enacted in March 2012 6 requires the government to identify assets that are
strategic to the national interest in the transportation, telecommunication and energy
industries. The decree provides for a duty of prior notification to the government of any
corporate resolution or proposed act or transaction, which may result in a transfer of
ownership or control over such strategic assets, and for the government to be able to veto
such transfer insofar as it would represent an actual threat to national security interests. The
decree also provides that the government may oppose, or issue instructions in connection
with, any transfer to non-EU persons of controlling interests in such strategic assets.
In addition, local rules or the terms of a concession may sometimes make
the change in control of the entity owning or operating certain assets or holding the
concession subject to prior notice, or a prior clearance of, the local issuing authority.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
The proprietary unbundling of the electricity industry has been substantially achieved
during the decade from 1998 to 2007, with the breakup of the infrastructure of the statecontrolled
incumbent monopolist (ENEL) into different companies.
This process resulted in the separation of the business functions of the previous
incumbent into (1) generation (ENEL SpA, EDISON SpA and a variety of other generation
companies); (2) ownership and operation of the HV and UHV transmission grid (mostly
Terna SpA, now publicly listed); and (3) ownership and operation of the MV and LV local
distribution grid and sale (ENEL Distribuzione and a variety of local utilities).
As to the gas industry, the chain of production upstream of the local distribution
pipelines is still largely dominated by the state-owned former monopolist (ENI), which
has also been broken down into separate companies.
Most of such upstream infrastructure is directly or indirectly owned by SNAM,
a listed holding company, which controls through separate companies the primary
transportation pipeline (Snam Rete Gas), the main regasifier operator (GNL Italia), the
main storage operator (Stogit) and one of the leading gas DSOs (Italgas).
SNAM is majority controlled by ENI, although separation is expected to take
place. A prime ministerial decree is expected by May 2012 on the transfer to Cassa
Depositi e Prestiti SpA of most of ENI’s stake in Snam Rete Gas.
ii Transmission/transportation and distribution access
Electricity transmission and gas transportation as well as electricity and gas distribution
infrastructures are operated on the basis of state concession having a duration of up to 12
years. The infrastructure operators are required to grant access to producers/generators
and sellers.
6 Law Decree No. 21 of 12 March 2012.
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iii Rates
Generally applicable tariffs for interconnection (dispatch, transportation, distribution
and metering services) are set by the AEEG on the basis of formulae that aim at a fair
remuneration of invested capital. The tariffs also include components to cover system
costs (e.g., the cost of decommissioning of nuclear plants, feed-in tariffs and other forms
of incentives for renewable sources).
iv Security and technology restrictions
The matter is regulated by EU Directive a 2008/114/CE issued within the framework of
the European Programme for the Protection of Critical Infrastructure, launched in 2006.
The Directive provides a framework for the identification and determination of security
measures and procedures for the protection of critical European infrastructure. The
Directive was locally implemented in 2011 7 and sets out procedures and responsibilities
for the protection of critical infrastructures and for the preparation and validation of
emergency plans. Operators must appoint a safety and security representative, prepare
an operator security plan, identify the critical assets of European critical infrastructures
and the relevant means of protection, identify all potential threats, vulnerabilities and
risks and outline the appropriate response plans. These plans must also address, among
others, IT threats and vulnerabilities.
IV
ENERGY MARKETS
i Development of energy markets
The market is operated by GME, a state-owned private company. An electricity market
has been in operation since 2004, and it consists of the following:
a a spot electricity market, where energy blocks are traded over a period of nine days
prior to the date of delivery; the market operates on an auction basis as bids/offers
are accepted under the economic merit-order criterion and taking into account
transmission capacity limits between zones;
b a forward electricity market, where trading of base-load and peak-load contracts
with monthly, quarterly and yearly delivery periods are carried out on a continuous
basis, with GME acting as central counterparty; and
c a platform for physical delivery of derivative contracts concluded on the IDEX
segment of the Italian stock exchange.
GME also operates the natural gas market (‘the M-Gas’) where parties admitted to the
‘punto virtuale di scambio’ (PSV, or virtual trading point) may make spot purchases and
sales of natural gas quantities where GME plays the role of central counterparty.
The M-Gas consists of the day-ahead gas market (the MGP-Gas) operating on
a combined continuous trading and a closing auction basis and intraday gas market
(MI‐Gas) operating on a continuous trading basis.
7 Legislative Decree No. 61 of 11 April 2012.
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The GME also operates P-Gas, the platform for trading of imported natural gas
and royalties on natural gas extracted under domestic concessions, and PB-Gas, the
platform for trading of balancing gas.
ii Energy market rules and regulation
The energy and gas markets operate under market rules approved by the Ministry of
Economic Development in consultation with the AEEG and as well as a number of
technical rules issued by the GME.
The electricity markets and each of M-Gas, P-Gas and PB-Gas have their own
set of market and technical rules. Market rules include criteria and procedures for
admission of market participants, trading and settlement rules, as well as sanctions and
sanctioning procedures in the event of a breach of market rules by or default by the
market participants. GME is generally responsible for market operations and oversight
as well as for the enforcement of market rules.
iii Contracts for sale of energy
Market participants are generally allowed to enter into individual contracts for the sale
of power and natural gas. Since 2003 (for gas) and 2007 (for electricity) all customers are
eligible to freely enter into contracts for the purchase of gas or power from sellers that
meet certain minimum requirements. Power and gas sellers must comply with certain
rules on transparency and fairness of information to customers under the supervision
of the AEEG, but the rates and contractual terms may be freely determined subject to
the aforementioned AEEG rules. Predetermined terms and conditions and rates are set
out by the AEEG for the ‘protected categories service’ (i.e., those retail clients and small
businesses that have not opted to join the liberalised market).
iv Market developments
Both the electricity and gas market have achieved a considerable level of liberalisation
and the country has implemented efficient exchanges for trading of electricity and gas
contracts, and radical developments in the way regulated exchanges for trading of gas
and electricity operate are not expected at this stage.
However, certain amendments to pricing mechanisms could be introduced to
address certain unintended consequences of the recent installation of a massive amount
of PV power generation plants with a view to reducing the impact on operators of
conventional plants and certain intraday pricing distortions. Input from photovoltaic
plants has driven up the cost of energy in the evening hours due to the need for operators
of conventional plants to concentrate the recovery of investment and inactivity costs in a
more limited time span, when generation by PV plants is not available. 8
The Ministry of Economic Development has been recently called to issue new
guidelines on price formation on the electricity markets within 120 days ‘in order to
control costs and guarantee the security and quality of the power supply also through the
enhancement of flexibility’ by way of the so-called liberalisation decree enacted on 24
8 AEEG report to the Senate Industry Commission on 18 April 2012.
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January 2012 and converted into law on 22 March 2012, ‘taking into due account the
increased production from renewable sources’.
On the gas markets there have been recent talks of allocating an increased
component of the cost of investment for infrastructure (namely, regasifiers and import
pipelines) to the retail tariff.
Pursuant to the liberalisation decree, customers falling in the ‘protected category
service’ will be charged a tariff more closely tied to market dynamics.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
The share of production from renewable sources has dramatically increased over the
past four years. This is due to public policy fostering the achievement of the 20/20/20 9
objectives under the EU climate and energy package through incentives in the form of
a feed-in premium for solar plants and green certificates for all other renewable sources.
The estimated aggregate installed capacity from renewable sources as at December
2011 was 41.532GW at the end of 2011, compared with 23.859GW at the end of 2008. 10
The burden allocated to Italy under the EU climate and energy package called for
17 per cent of primary energy consumption (subdivided into electrical, heat and transport)
to be generated from renewable sources with 26 per cent of electricity generation to come
from renewables (projected to be equal to 100TWh per annum in 2020). Energy generated
from renewables in 2011 has already reached 94TWh per annum. 11
Solar
The growth in energy from renewable sources is mostly attributable to PV installations,
which rose dramatically from 0.432GW in 2008 to 3.470GW in 2010, and then to
12.750GW in 2011.
A large share of the installed capacity benefits from the 20-year feed-in premium
that was granted under the second Conto Energia 12 to photovoltaic plants commissioned
between 2007 and the second quarter of 2011. The incentives, whose cost is charged
to consumers as a component of the electricity bill, were among the highest available
in the world between 2009 and 2011 and prompted a staggering acceleration of new
installations during those years.
Installations peaked between the third quarter of 2010 and the second quarter
of 2011 due to the combined effect of the enactment of the third Conto Energia 13
providing for generally lower and then steeply declining (depending on the month of
9 20 per cent reduction in emissions, 20 per cent renewable energies and 20 per cent improvement
in energy efficiency by 2020.
10 GSE, ‘Impianti a fonti rinnovabili in Italia’, 6 March 2012.
11 Recitals to the draft fifth Conto Energia and slides used by the Italian government to present
its contents to the press.
12 Ministerial Decree 19 February 2007.
13 Ministerial Decree 6 August 2010.
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commissioning) tariffs for plants commissioned from 2011 onwards and the so-called
Salva Alcoa Law, 14 which allowed plants that had reached mechanical completion in
2010 to continue to benefit from the feed-in tariff under the second Conto Energia,
provided they achieved full commissioning by 30 June 2011.
On 3 March 2011 the government approved Legislative Decree No. 28/2011,
which provided a comprehensive framework for incentives for renewable energy going
forward (‘the Renewables Decree’). One of its effects was the reduction of the availability
of the third Conto Energia to plants commissioned on or before 31 May 2011, which
then led to the approval of the fourth Conto Energia, 15 which provided for further cuts
and introduced annual and cumulative caps in terms of additional installed capacity for
larger plants commissioned after August 2011. Access to the feed-in premium by larger
plants (ground installations in excess of 200kW and rooftop installations in excess of
1MW) was granted or denied according to a ranking system based on several different
criteria including the enrolment with a registry kept by GSE. This led to a further rush
to complete ongoing projects before the registration regime kicked in. The fourth Conto
Energia called for a review of the incentive scheme once the aggregate annual expenditures
for feed-in premiums approached €6 billion. This amount is now being approached and
on 12 April 2012 the government disclosed the terms of the draft fifth Conto Energia,
which provides the incentives, now in the form of a feed-in tariff, from the earlier of
1 July 2012 until 2016, or the reaching of an aggregate cap in additional expenditure
equal to €500 million. Qualifications based on a ranking system for sub-caps for each
six-month period is extended from only large to virtually all plants (currently the only
exception being those having an installed capacity of less than 12kW). The fifth Conto
Energia has been submitted to the State–Regions Steering Conference and is expected to
be approved by the end of May.
Consistent with the increasingly restrictive policy trends on further PV capacity
development, the aforementioned Decree (No. 1/2012) inhibited access to the
incentives to ground PV installations on farm land (other than those already approved
for construction at the time of its coming into force), adding to the limitations in power
and density of ground installations on farm land that had already been introduced by the
fourth Conto Energia.
Policymakers expect new solar installations to stabilise at 2.5 to 3GW per annum.
PV technology is expected to reach grid parity no later than 2016 and, according
to some operators, as early as 2013 or 2014.
Other renewable sources
Plants generating electricity from renewable sources other than PV are currently
incentivised through the awarding of ‘green certificates’ in proportion with electricity
generated multiplied by coefficients that are different for each technology. This form of
incentive dates back to Legislative Decree No. 79/1999 (the so-called Bersani Decree).
14 Law No. 129/2010.
15 Ministerial Decree 5 May 2011.
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Energy producers or importers accounting for more than 100 GWh of production/
import per year are required to contribute to the grid a minimum quota (originally 2
per cent, which gradually increased to 6.8 per cent in 2011) of their production into the
grid. This minimum quota can be complied with by buying a corresponding amount of
green certificates.
Green certificates are issued by GSE and can be sold over the counter or through
a trading platform operated by the GME.
The market for green certificates has been characterised by a structural bid–offer
imbalance that would have resulted in prices too low for investment in renewable sources
to be viable; however, GSE acts every year as a buyer of last resort of unsold green
certificates from the previous year at the annual average price of electricity defined in
such year by the AEEG. The duration of the green certificate regime is currently set at 15
years as of commissioning of the plant.
The Renewables Decree provides for the guidelines for a phase-out of the green
certificate system and its replacement with an all inclusive feed in tariff mechanism
applicable to plants commissioned after 31 December 2012. Plants commissioned before
that date will continue to benefit from the green certificates until the end of 2015 when
they will converge towards a feed-in tariff system and the GSE will continue to purchase
the unsold certificates relating to the electricity produced during the period 2011–2015 at
a price equal to 78 per cent of the reference price for the certificates for the previous year.
The new feed-in tariff regime must be designed to take into account the following
main principles:
a a fair compensation for investment and operating expenses;
b a duration equal to the average lifetime of the plants; and
c stability for the whole period the plant benefits from incentives.
Larger plants having an installed capacity in excess of 5MW commissioned after
1 January 2013 will compete to obtain a feed-in tariff through descending-price
auctions, whereas smaller plants (i.e., those that are smaller than 5MW but greater than
50kW) commissioned after such date will compete for the allocation of feed-in tariffs
within sub-caps for six-month periods based on a registry enrolment and ranking system
(similar to that provided for by the fifth Conto Energia for PV plants). The amount of
the feed-in tariff will also be a function of the renewable technology deployed.
The draft of the ministerial decree providing detailed rules for the implementation
of the above has been presented to the public at the same time as the fifth Conto Energia.
It has been similarly submitted to the State–Regions Steering Conference and is expected
to be approved by the end of May.
The objective is to increase annual expenditure for incentive to non-PV renewable
from current amount of €3.5 billion to €5.5 billion. The target is an average additional
1.2GW per annum installed capacity. Incentives are expected to be phased out by 2020.
ii Energy efficiency and conservation
Public support to the achievement of energy goals in furtherance of the EU climate and
energy package objectives is two pronged: a ‘white certificate’ scheme, and a programme
of tax deductions on energy efficiency and conservation investment on buildings.
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White certificates
White certificates (energy efficiency certificates, locally known as TEE) were first
introduced by the Ministerial Decree of 20 July 2004, and then the programme was
overhauled by the Ministerial Decree of 21 December 2007 and the Legislative Decree
No. 11/2008. Similar to green certificates, the incentives revolve around the obligation
imposed on gas and electricity DSOs with more than 50,000 customers to achieve certain
minimum primary energy savings targets that are expressed in tons of oil equivalent
(‘toe’) and increased on a yearly basis. The cumulative target for 2012 stands at 6 million
toe. A DSO or a voluntary participant in the scheme (DSOs with less than 50,000
customers, energy service companies, DSO parents or affiliates or companies that have
appointed energy managers pursuant to Section 19 of Law No. 10/91) may prepare and
submit energy-efficiency projects with a view to obtaining white certificates. The project
must comply with the criteria set out by the AEEG and be validated from a technical and
administrative standpoint by ENEA. 16 The project, once validated, entitles the applicant
to be issued by GME one white certificate for each toe saving achieved. The certificates
may be traded on the platform operated by GME or sold to DSOs over the counter.
Tax deductions
The tax-deduction programme provided for a tax credit equal to 55 per cent of investment
made in increased energy efficiency and conservation of buildings, to be broken down into
equal instalments over a period of 10 years and subject to a cap of €60,000 (55 per cent
of €109,091). The works must fall into identified categories of energy conservation and
optimisation works and be performed as part of renovations of existing residential heated
buildings. The programme has been extended to the 2012 fiscal year and from 2013 will
merge with the more general 36 per cent tax credit on investments for building renovations.
iii Technological developments
Italy is at the forefront of European research on smart grids. In 2011 Italy was the European
leader in terms of financial resources committed to research projects on smart grids
(accounting for 55 per cent of the aggregate) and was third in terms of number of research
projects it leads and or coordinates (5.5 per cent of an aggregate of 219 projects). 17
Since 2001, ENEL has been deploying a smart electronic metering system to
its customer base, as well as providing other utilities capable of two-way real-time
monitoring of input and consumption, which is now in operation with its 34 million
customers (equal to 99 per cent of ENEL’s customer base) and 4 million other utilities
customers. 18 Italy arguably has the largest operating smart grid in the world.
Some research has been undertaken into enhanced smart grids, including an
EU-financed ‘MV smartgrid’ project in four southern Italian regions, a pilot project
16 The Italian National agency for new technologies, energy and sustainable economic
development.
17 ‘Smart Grid projects in Europe – lessons learned and current developments’, JRC Reference
Reports, Luxembourg: Publications Office of the European Union, 2011.
18 Source: ENEL.
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started in 2012 in Isernia for an advanced smart grid including smart programmable and
metering-capable household appliances, non-programmable renewable input prediction
systems and electric car charging systems.
Renewable energy incentives have been structured over time to allow higher
remuneration of and access to separate sub-caps to certain advanced high-efficiency
technologies (e.g., solar concentration plants and innovative integrated PV plants).
ENEA and ENEL have jointly developed – and commissioned in 2010 –
Archimede, in Sicily: a pilot project for the realisation of a 5MW solar concentration plant
combined with a conventional CCGT plant that uses molten salts as heat accumulators
and vectors.
Several Italian companies, including Enel and Terna, are partners in the Desertec
initiative aimed at realising a joint African–European initiative for the realisation of solar
concentration and large-scale wind-generation plants in northern Africa and the HV DC
lines for long-range transportation of electricity to the European grid.
VI
THE YEAR IN REVIEW
i Key decisions, legislation, cases or policy changes
Some of the key developments in energy legislation 2011 and 2012 include the following:
a Approval of the Renewable Energy Decree (Legislative Decree No. 28 of 3 March
2011), which provides a comprehensive legislative framework for the development
of generation from renewable sources in Italy consistent with the National Action
Plan that was approved in 2012 and the consequent approval of the fourth Conto
Energia.
b The popular vote on 12 and 13 June 2011, which, in the aftermath of Fukushima,
scuttled the plans for revamping the Italian nuclear-generation project that had
been fostered by the Berlusconi government.
c The extension (by virtue of Law Decree No. 138 of 13 August 2011, No. 138)
of the Robin Hood Tax for fiscal years 2011 to 2013 to companies operating
in the energy-regulated sectors (despatch, transmission and distribution) and to
renewables operators (biomass, wind and PV solar), coupled with a reduction of
the revenue threshold that triggers the application of the tax to €10 million and
the increase of the relevant additional tax rate from 6.5 per cent to 10.5 per cent.
d The ‘Liberalisation Decree’ (Law Decree of 24 January 2012, No. 1, converted
into law by Law 24 March 2012, No. 27), which provided for:
• some key steps and the timeline for the unbundling of SNAM Rete Gas
from ENI;
• the criteria for the determination by the AEEG of remuneration on a
single-asset basis of investment by Terna in the grid;
• a ban on further development of PV plants on farm land; and
• the issuance by the Ministry of Economic Development of the guidelines
for a reform of the electrical market.
e The approval on 13 April 2012 of the drafts of the fifth Conto Energia and the
decree on incentives to non-PV renewables.
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f
The draft law for the parliamentary delegation to the government to reform the
tax system approved on 16 April 2012, which includes a delegation to introduce a
carbon tax aimed at generating revenue to finance incentives for the development
of generation from renewable sources in coordination with similar action plans at
EU level.
ii Key mergers and acquisitions
Key M&A transactions in 2011 and up to 15 April 2012 include the following: 19
a 22 December 2010: AXA Private Equity, the France-based private equity firm,
and Fondi Italiani per le Infrastrutture SGR SpA, the Italy-based private equity
firm, acquired E.ON Rete Srl, the Italy-based gas distribution business, from
E.ON AG, the listed Germany-based power and gas company, for €290 million.
b 31 March 2011: GDF Suez SA, the listed France-based natural gas and electricity
supplier, has acquired a 30 per cent stake in Tirreno Power SpA, the Italy-based
company that generates thermoelectric and hydroelectric power, from Acea SpA,
the listed Italy-based water and electricity utility group, for $285 million.
c 18 May 2011: Antin Infrastructure Partners SAS, the France-based private
equity firm specialising in the infrastructure sector has acquired Aprilia Solar (the
Italy‐based operator of photovoltaic plants and distribution of electricity), BS
Solar Srl (the Italy-based company engaged in the production of electricity) and
PN Solar Srl (the Italy-based company engaged in the production of electricity)
from Volteo Energie Srl, the Italy-based holding company of Kinexia SpA engaged
in the renewable energy sector and ER Energia Rinnovabile Srl, the Italy-based
subsidiary of Volteo Energie Srl for €105 million.
d 6 June 2011: AXA Private Equity, the France-based private equity firm, and
Fondi Italiani per le infrastrutture SGR SpA, the Italy-based private equity firm
acquired 100 per cent of G6 Rete Gas (GDF Suez), a gas distributor with 990,000
customers, for €772 million.
e 23 June 2011: ILVA SpA, the Italy-based iron and steel producer and a subsidiary
of Riva Group, the Italy-based iron and steel producer has agreed to acquire CET 2
and CET 3, the Italy-based electricity power plants located at Taranto, from Edison
International SpA, the listed Italy-based energy company, for €160 million.
f 23 June 2011: ERG SpA, the listed Italy-based oil company that refines,
distributes and markets crude oil and refined petroleum products, has agreed to
acquire IVPC Power 3 Srl, the Italy-based operator of wind farms, from Italian
Vento Power Corporation, the Italy-based company engaged in the production,
construction, and operation of wind farms, for €100 million.
g 29 July 2011: Rete Rinnovabile Srl (RTR Group), the Italy-based solar energy
company and subsidiary of Terra Firma Capital Partners III, LP, a UK-based
private equity fund of Terra Firma Capital Partners Limited, the UK-based
private equity firm, has agreed to acquire Nuova Rete Solare Srl (NRTS), the
Italy-based company that owns, operates, and manages three photovoltaic plants,
19 Source: Mergermarket.
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h
i
j
from Suntergrid SpA, the Italy-based company engaged in construction and
maintenance of electricity transmission grids and plants for the generation of
electricity and a subsidiary of Terna – Rete Elettrica.
29 July 2011: Rete Rinnovabile Srl, the Italy-based solar energy company and a
portfolio company of Terra Firma Capital Partners Limited, has agreed to acquire
10 photovoltaic plants with a combined installed capacity of 78MW from HV
grids, for an estimated €250 million.
16 February 2012: Electricité de France SA (EDF), the France-based generator,
provider and distributor of energy, has agreed to acquire a 50 per cent stake in
Transalpina di Energia Srl, the Italy-based energy joint venture between Delmi
SpA and EDF, from Delmi SpA, the Italy-based holding company and subsidiary
of A2A SpA, for €704 million. Transalpina di Energia already owns 61.3 per cent
in Edison SpA’s voting share capital.
16 February 2012: Delmi SpA, the Italy based holding company and subsidiary
of A2A, has agreed to acquire a stake in Edipower, the Italy based energy provider,
from Edison International SpA, the Italy based provider and distributor of
electricity, and Alpiq, the Switzerland based distributor and provider of electric
power, for a consideration of approximately €804 million. Edison and Alpiq will
sell their 50 per cent and 20 per cent stakes in Edipower respectively.
iii Market developments and trends in 2012
Some of the developments that could currently be expected in 2012 are as follows:
a A significant contraction of development of new PV installations due to the
combined effect of the credit crunch, of the uncertainties as to access to tariffs
created by the fifth Conto Energia and the decree on incentives to non-PV
renewable plants; new developments will have to be conceived with a view to
achieving grid parity.
b The acquisition on the secondary market of the best and largest existing PV
installations by both industrial (e.g., multi-utility companies) and financial (e.g.,
private equity, infrastructure and pension funds) players.
c The launch of the process of separation of SNAM from ENI.
d Increased public focus on energy efficiency.
e The possible increase or application of charges for the use of infrastructure and
grid stabilisation for renewable plant operators.
f The introduction of a carbon tax and switching of the burden of incentives to
renewables from the electricity bill to revenues generated by the carbon tax.
g Possible mergers and consolidation of municipal multi-utilities to achieve critical
mass to invest effectively in R&D and infrastructure development and possibly
operate internationally.
h A focus on the development of strategic infrastructure to secure supply and stock of
natural gas (import pipelines, regasifiers and storage facilities), and simplification
of the relevant permit process.
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Chapter 13
Japan
Reiji Takahashi, Atsutoshi Maeda, Shun Hirota and Yuko Suzuki 1
I
OVERVIEW
Japan is a country with limited energy resources and as such, energy legislation in Japan
can essentially be divided into legislation concerning electricity and that concerning gas.
Electricity serves as an indispensible element of the social infrastructure of Japan
and in recognition of the high level of public interest attached to the provision of electric
utilities, certain market entry regulations are in place to regulate the industry. Also, because
electric power consumers – especially general consumers – currently have virtually no
options in selecting an electric power supplier, strict regulations are in place to monitor
the content of all contracts executed between power companies and such consumers in
the interests of consumer protection. Due to the events of the recent earthquake and the
accident at the Fukushima nuclear power plant, however, a movement seeking to amend
the current legislation can now be discerned, along with an increased interest in future
developments in this area.
The gas industry in Japan can be divided into the following two major enterprises:
the town gas industry, which is the primary source of natural gas to consumer residences
through piping, and the liquefied petroleum gas (‘LPG’) industry, which provides LPG
via cylinders to consumers in areas where piped gas is not yet available.
In principle, the approval required for entry into the town gas industry as well as
the price of the gas itself are strictly regulated under Japanese law. In contrast, entry into
the LPG industry only requires registration with the relevant authority and prices for
such LPG may be freely set by the provider.
As of March 2008, statistics show that around 28.38 million consumers utilise
town gas whereas the corresponding number of consumers for LPG is around 26 million.
These statistics are in direct competition with each other.
1 Reiji Takahashi and Atsutoshi Maeda are partners and Shun Hirota and Yuko Suzuki are
associates at Anderson Mōri & Tomotsune.
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II
REGULATION
i
The regulators
The energy industry in Japan, which encompasses electric power and gas, is regulated
by the Ministry of Economy, Trade and Industry (‘the METI’) or, more specifically, the
Ministry’s Agency for Natural Resources and Energy. The Ministry of Economy, Trade
and Industries Establishment Act provides for the Ministry’s jurisdiction over matters
concerning comprehensive policies in relation to energy and mineral resources and over
matters concerning the securing of the stable and efficient provision of gas, electric power
and heating to Japan, and for the handling of such matters by the Ministry’s Agency for
Natural Resources and Energy.
Main sources of law and regulation
The Electricity Business Act is the main source of legislation regulating businesses
involving the generation, transmission and sales (distribution) of electric power
(collectively, ‘electric power utilities’). In addition to this, the Electricity Business Act
Enforcement Orders and the Ordinance for Enforcement of the Electricity Business Act
further provide detailed regulations for the enforcement and government of the system
provided under Electricity Business Act.
As for nuclear power, regulation is provided in the Atomic Energy Fundamental
Act, the Act on Compensation for Nuclear Damage and other such specialised
legislation. 2
The Gas Business Act is the main source of legislation regulating businesses
involving town gas. In addition to this, the Gas Business Act Enforcement Orders
and the Ordinance for Enforcement of the Gas Business Act further provide detailed
regulations for the enforcement and government of the system provided under Gas
Business Act.
As for LPG, the main source of legislation regulating businesses involving LPG
is the Act Concerning the Securing of Safety and the Optimisation of Transaction
of Liquefied Petroleum Gas (‘the LP Gas Act’). In addition to this, the LP Gas Act
Enforcement Orders and the Ordinance for Enforcement of the LP Gas Act further
provide detailed regulations for the enforcement and government of the system provided
under the LP Gas Act.
2 Although, since the accident at Fukushima in 2011, various legislative acts for compensation
and support pursuant to nuclear damage have been enacted in Japan and there have also been
significant recent developments in these legal fields, these developments will nevertheless not
be covered in this chapter. For an update on such developments, please refer to Naoki Iguchi,
Ava Tabila and Yuko Suzuki, ‘After The Quake: Rethinking Japan’s Renewable Energy Policy’,
SEERIL Current Practice, vol. 7, p. 21.
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ii Regulated activities
Electricity
Under the Electricity Business Act, entities engaging in electric power utilities subject to
regulation are categorised under the following five groups:
a entities supplying electric power to meet the general demand of consumers and
businesses (‘general electric utilities’);
b business operators utilising production facilities the output of which is in excess
of 2 million kW for the provision of electric power to general electric utilities
(‘wholesale electricity utilities’);
c business operators that execute agreements for the supply of electric power in
excess of 50kW and provide such electric power through the use of electric lines
and cables owned by general electric utilities (known in Japan as ‘power producer
suppliers’ or ‘PPSs’);
d business operators utilising their own privately owned power production facilities,
electric lines and cables to supply electric power to specified consumers (‘specified
electricity utilities’); and
e business operators that have executed long-term agreements with general electric
utilities for the supply of electric power (known in Japan as ‘independent power
producers’ or ‘IPPs’).
Of the five aforementioned categories, most prominent are the general electric utilities.
There are currently 10 such regional electric companies in Japan, their representative
being the Tokyo Electric Power Co, Ltd (‘TEPCO’). These companies at one time held
regional monopolies over Japan’s electric power industry and even now continue to cut
imposing figures in the energy industry.
As for the remaining categories, two entities (Electric Power Development Co Ltd
(or J-Power), and the Japan Atomic Power Company) currently fall under the category
of wholesale electricity utilities; 52 corporate entities currently exist as PPSs, represented
by the Ennet Corporation, a company established by the joint venture of TOKYO GAS
Co Ltd, OSAKA GAS Co Ltd and NTT Facilities Inc; various others operate under the
heading of specified electricity utilities, one of the more famous being Roppongi Energy
Service Co Ltd, a supplier of electric power whose generators are located beneath the
Roppongi Hills business complex in Tokyo’s Minato ward and which supplies electric
power to the entire Roppongi Hills complex. Many still function as IPPs, such as the
large majority of business operators utilising feed-in tariffs (‘FITs’) to carry out solar and
wind power-generation businesses discussed in Section V, infra.
Entities intending to engage in any general electric utilities, wholesale electricity
utilities and specified electricity utilities activities are required to obtain approval
from the METI prior to commencing of such business. Criteria for the grant of such
approval include whether the applicant has sufficient financial resources and technical
capabilities to properly perform such businesses or whether such business is based on a
reliable business plan. Applicants will be judged on their ability to cater to the energy
consumption demands of the general public and whether they will be capable of running
a sound business. Applicants are required to submit their applications for approval to the
METI in the form prescribed by the relevant laws. Processing time for such applications
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will depend on the approval applied for. In general, an application for approval in
relation to a general electric utility will require three to four months, whereas approval
for a wholesale electricity utility will require anywhere from five weeks to two months
with approval for specified electricity utilities requiring five to eight weeks.
In contrast, entities intending to engage in any of the activities of PPSs are only
required to file a notification with the METI upon the commencing such business.
Even in cases where neither approval nor notification are required for
commencement of business, when conducting an electric power generation business,
the METI must still be notified of the installation work plans of the power stations
depending on the type of power generation and scale of the generator facilities (additional
authorisation will also be necessary in the event of installation of nuclear power stations).
The majority of entities deemed as IPPs will likely be subject to these requirements.
Gas
Town gas businesses targeting general consumers
The Gas Business Act stipulates that entities intending to perform gas businesses targeting
households, corporations and other such general consumers must obtain the relevant
approval to become an operator of such gas businesses (‘general consumer gas utility
business operators’ or GCGUBOs’) from the METI.
Applications for the relevant approvals involve the necessary submission of
application forms in which statutorily required data such as details of the service area,
gas generating facility and such other necessary information are described. The criteria
stipulated in the Gas Business Act for the grant of such approval include the existence of
sufficient demand for gas in the intended service area, the adequacy of the applicant’s gas
provision capability, whether the applicant’s entry into the market will result in an excess
in the supply of gas in the service area, whether the applicant has sufficient financial
resources and technical capabilities to properly perform such business, and whether the
proposed gas utility is based on a reliable business plan.
Although the foregoing criteria do not specifically limit town gas providers to one
provider per service area, in reality, the public administrative procedures utilised by the
relevant regulatory authorities requiring that the applicant’s entry into the market does
not result in an excess in the supply of gas in the service area effectively limits each service
area to a single town gas provider.
If all necessary criteria are met, the METI will be required to grant its approval.
In principle, the entire application and approval process will require around four months
to complete.
As of March 2008, 212 GCGUBOs have received the necessary approvals and are
currently operating such businesses (of this number, 32 are public utilities).
Regional monopolies have been recognised in relation to these business operators
and, accordingly, the percentage of operators for the service areas in large metropolitan
areas is understandably high. The share of the largest operator Tokyo Gas (service area:
Kanto region with Tokyo as its main focus) currently accounts for about 35.8 per cent
of the market whereas the combined share of the four major corporations (Tokyo Gas,
Osaka Gas, Tohou Gas and Saibu Gas) providing service areas in large metropolitan areas
accounts for about 73.1 per cent (based on sales volume as of January 2012).
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Other types of town gas business
In addition to the above, the Gas Business Act also imposes certain restrictions on
operators providing LPG to housing estates and other such residences by entities through
the use of simplified gas-generating facilities (‘community gas utility business operators’),
facilitating the large-volume supply of gas (defined as the provision of gas to consumer
in excess of 100,000 cubic metres per year, discussed in greater detail below) via gas
pipelines over a certain size, which are independently maintained or utilised by such
operators (‘gas pipeline service operators’) and undertaking the business of providing
large-volume supply of gas to consumers (‘commercial-scale gas suppliers’).
Seller of LPG
The LP Gas Act stipulates that necessary registration for the sale of LPG must be obtained
from the Minister for Economy, Trade and Industry when intending to establish sales
offices catering to two or more prefectures and from the prefectural governor when
catering to only one prefecture.
Registration involves the necessary submission of application forms in which
statutorily required data, such as details of the sales office, gas storage facilities and
other necessary information, are described. Applicants will be registered with the
corresponding authority (either the Minister for Economy, Trade and Industry or the
prefectural governor) as long as there are no applicable statutory grounds for denial of
the application.
Registrations will require 30 days to process or 15 days if the registration is applied
for via the relevant authority’s electronic information processing system.
As of March 2011, the number of business operators that have obtained the
necessary registrations and are currently engaged in the sale of LPG has risen to 20,047.
Entry barriers to this section of the industry are low and a large number of small and
medium-sized businesses have been entering into the LPG industry in which even retail
rates are not regulated. Due to the aggressive introduction of all-electric technology town
gas and other such products from the electric power companies, however, this figure is
still less than half of when LPG sales were at their peak (54,000 operators in 1967).
iii Ownership and market access restrictions
There are no particular restrictions on foreign investment in the electric power industry
or the gas industry. The only existing restrictions are those imposed by the general laws
regulating the entry of foreign investment in Japan stipulated in the Foreign Exchange
and Foreign Trade Act. For example, if a foreign investor were to obtain 10 per cent or
more of the shares of an electric power or gas utility (including both town gas and LP gas),
intend to set up a branch for the conduct of electric power or gas business or otherwise
engage in any such activities, the Foreign Exchange and Foreign Trade Act requires that
the relevant authorities be notified in advance of such activities. Furthermore, in the
event of the performance of any such activities requiring advance notification of the
relevant authorities, a follow-up report after such performance must also be submitted
accordingly. Both prior notification and follow-up reports must be submitted to the
Bank of Japan, which in turn will facilitate the submission of such notifications and
reports to the Minister of Finance or such other relevant minister in charge.
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iv
Japan
Transfers of control and assignments
Electricity
The prior approval of the METI is necessary in the event that a transfer of the business of
a general electric utility, wholesale electricity utility and specified electricity utility in its
entirety is contemplated, or in the event of a merger or demerger whereby the surviving
entity completely absorbs any such business. The criteria for the granting of such
approval is the same as that for the original grant of approval to operate such businesses.
Notification of the METI is also required upon the handover of any equipment or
facilities in relation to general electric utilities, wholesale electricity utilities and specified
electricity utilities.
In the case of a PPS, in the event of any transfer of such business in its entirety
or of any merger or demerger whereby the surviving entity completely absorbs such
business, the succeeding entity is only required to notify the METI.
Gas
The transfer or acquisition of all or part of a general consumer gas utility business
requires authorisation from the METI before it can be effective, as does the merger or
demerger of any entity that is a GCGUBO whereby all or part of a general consumer gas
utility business is succeeded by the surviving company. The criteria for the grant of such
required authorisation is the same as that for the original grant of approval to operate
such businesses.
In the case of LPG businesses, however, in the event of any transfer of such business
in its entirety or of any merger or demerger whereby the surviving entity completely
absorbs such business, the succeeding entity is only required to notify the METI or the
prefectural governor as relevant.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Electric power
Integrated system for the production and transmission of electric power
In Japan, following the close of World War II and up until 1995, the production and
transmission of electric power as well as the its assorted related retail operations, were
run as a single integrated utility by the 10 electric power companies, each with their
respective regional monopolies over the 10 main regions of Japan.
Since 1995, after four stages of institutional reform, Japan finally realised the
liberalisation of its electric power generation and sales sectors. That being said, it should
still be noted, however, that the electric power transmission sector is still very much
dominated by the aforementioned 10 power companies that have continued as general
electricity utilities (as only PPSs are capable of transmitting electric power using their
own electric power transmission facilities). The securing of the stable provision of electric
power has been cited as a reason for this and as a result, general electricity utilities (electric
power companies such as TEPCO) have an overwhelming competitive advantage
in the electric power industry over other competitors engaged in the production and
transmission of electric power and related retail operations.
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Notwithstanding the foregoing, because the electric power distribution grid is
a public infrastructure, measures have been implemented to prevent general electricity
utilities from abusing their dominant market positions and to ensure the transparency of
the electric power industry.
First, general electric utilities are required to notify the METI of the contents of
their electric power transmission service agreements and may only execute electric power
transmission service agreements containing such notified terms and conditions. If any
such entity were to refuse to provide its electric power transmission services without a
justifiable reason, the METI has the authority to order such entity to provide its services.
Second, general electric utilities are forbidden from transacting with specific
business operators in relation the provision of electric power transmissions services if
pursuant to the transaction such operators are granted unfair advantages or disadvantages.
Third, the electric power transmission sectors of general electricity utilities are
required to keep their accounts separate from each other and the misappropriation of
information between entities is strictly prohibited.
Last, the Electricity Business Act also provides for the establishment of
organisations to support electricity transmission and distribution and that perform
functions such as the propagation of rules regulating electric power transmission and
monitoring of compliance thereto.
Separation of electric power transmission sectors
Despite the aforementioned promotion of more transparency and fairness in electric
power transmission services provided under the Electricity Business Act, the cost of such
services is still relatively costly (although somewhat dated, statistics from the energy
transmission and distribution sector indicate that the combined excess profits of the 10
power companies in 2006 was roughly ¥850 billion) and this inhibits the entry of new
entrants into the electric power generation and related retail operation sectors. This,
coupled with the cessation of operations of almost all the nuclear power plants in Japan
following the accident at Fukushima, has resulted in the current feeling in Japan that the
expansion of electric utilities by operators other than these 10 power companies is key to
maintenance of the provision of electric power to Japan.
As a result, on 27 December 2011, the Agency for Natural Resources and Energy’s
Electric Power Systems Reform Taskforce announced that in order to consolidate the
competitive environment and promote the entry of new business operators into the
electric power generation and retail operations sectors, it would be necessary to study the
separation and neutralisation of the general electricity utilities from the electric power
transmission sector and publish the results of such study. 3 Future developments in this
regard will be carefully observed and noted.
Fully distributed cost method
General electric utilities are required to obtain the approval of the METI in relation to the
setting of rates and other conditions for the supply of electric power. A condition for the
3 www.meti.go.jp/committee/kenkyukai/energy/denryoku_system/007_giji.html.
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grant of such approval is that the ‘rates consist of fair costs incurred as a result of efficient
management and fair profits’. Calculation of electricity rates is supposedly subject to the
General Electric Utility Supply Provisions’ rules for fee calculation, which aim to limit
costs and reduce electricity prices by making ‘efficient management’ a requirement for
all such operators. In reality, however, it has been pointed out that TEPCO can easily
declare prices higher than necessary and unjustifiably increase electricity rates and many
share serious doubts as to the ability of the METI to monitor it.
ii Gas
Transportation obligations for town gas
As mentioned earlier, because GCGUBOs are, pursuant to public administrative
procedure, restricted by the practical principle of one town gas service provider per
service area, it has been acknowledged that town gas provider monopolies exist within
certain regions.
In exchange for such monopoly, GCGUBOs are obligated to broaden the piping
grid, in other words to provide gas transportation. As mentioned later in this article, the
revitalisation of competition through the utilisation of the piping grid by GCGUBOs in
order to liberalise rates for commercial-scale supplying of gas is highly anticipated.
Nevertheless, current transportation rates are still relatively expensive and
revitalisation of competition merely through the utilisation of the piping grid by
GCGUBOs is far from sufficient. As of March 2008, of the 207 new entrants to the
commercial-scale gas supplier industry, only 52 entrants will be utilising gas transportation
– barely 25 per cent.
Rate system for gas businesses
A GCGUBO wishing to possess a regional monopoly, because its consumers lack the
freedom to choose their provider, is required to base its rate upon its costs incurred
while under ‘efficient management’ plus a reasonable rate of return (a rate calculated
by the FDC) as stipulated in the general supply provisions approved by the METI.
Costs incurred while under ‘efficient management’ refers to costs assumed to be
incurred by a GCGUBO in its business operations pursuant to the necessary exercise
of its corporate activities, while ‘reasonable rate of return’ refers to the reasonable total
amount of production costs, provision and distribution costs and general administrative
costs as calculated based on actual and realistic future prospects of operations, plus the
amount of any funds obtained from interest and dividends to the extent fairly raisable
or attainable respectively, as necessary for the realisation of the reasonable development
of the business.
Raising of rates is subject to the approval of the METI, however, the lowering of
rates is not subject to such requirement and merely requires notification of the relevant
change in rate.
LPG pricing is not subject to regulation and prices may be set as negotiated
between the relevant parties of each transaction. Because of the accumulation of retailer’s
overheads, which accounts for over 60 per cent of the retail price of LPG, said retail price
of LPG has become more expensive than that of town gas.
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IV
ENERGY MARKETS
i
Japan Electric Power Exchange
The Japan Electric Power Exchange (‘the JEPX’) exists for the benefit of all electric powerrelated
transactions. It was founded in 28 November 2003 as a market for the commodity
trading of electric power and serves as an intermediary for electric power spot trading,
forward transactions and other such transactions. (It is possible to undertake both buy
and sell orders through the JEPX.) In order to participate in electric power commodity
trading on the JEPX, membership as a trade affiliate is necessary. At 16 February 2012,
54 companies are trade affiliates of the JEPX.
The JEPX is managed by a general incorporated association comprising electric
power companies and other such entities. It is a private exchange that operates and is
regulated by its own market rules.
ii Terms and conditions of supply
Electricity
General electric utilities are required to only execute contracts with consumers, the
terms and conditions of which have been approved by the METI. Such entities are
also prohibited from refusing to supply electric power to consumers unless there are
legitimate grounds for doing so.
Additionally, specified electricity utilities are required to notify the METI of the
contents of their electric power supply contracts.
In direct contrast, PPSs are free to set the terms and conditions of their electric
power supply contracts at their discretion, based only on negotiations with their relevant
counterparties.
Gas
Obligation to supply
In recognition of the inevitably monopolistic nature of the general consumer gas utility
business and other such considerations, GCGUBOs are subject to an obligation to
supply gas and accordingly are prohibited from rejecting an application for the supply
of gas received from a consumer and, in principle, from cutting off gas already supplied
to a consumer.
This is not the case with LPG and no such obligations are imposed on LPG
business operators.
Liberalisation of the town gas business
As a result of amendments to the relevant legislation, the town gas industry is currently
experiencing an overhaul of its competitive environment due to the relaxation of
regulations. Specifically:
a it has become possible for a town gas supplier to supply gas to the service area of
another town gas supplier or other ‘white’ areas (areas not already serviced by any
specific town gas supplier);
b companies other than town gas suppliers may now enter into the commercial
scale gas utility business;
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c
d
pricing for commercial scale gas supplying has been liberalised; and
in order to encourage new entrants to enter the market, a gas transport system
whereby the utilisation of existing gas piping belonging to other business operators
is allowed has been set up.
In particular, the scope of the liberalisation of commercial scale gas supply pricing has
been progressively expanding due to legislative amendments. Beginning with the first
round of reforms in March 1995, which saw the liberalisation of the rates for the supply
of gas to consumers whose annual usage exceeded over 2 million cubic metres, as of the
fourth round of reforms, which took effect from April 2007 the rates for supply of gas to
consumers whose annual usage exceeds 100,000 cubic metres have also been liberalised,
accounting for the liberalisation of roughly 62 per cent of the total volume of town gas
sales in Japan.
As a result of these efforts, 28 new gas companies have entered into the gas industry
(based on approval applications and notifications as of 1 July 2009) and as of 2008,
12.2 per cent of the total volume of commercial-scale gas supplied can be attributed to
such new entrants. New entrants entering into commercial-scale gas supplier business
include such entities as electric power companies, international natural gas utilities and
commercial enterprises.
iii Market developments
Electricity
The Agency for Natural Resources and Energy’s Electric Power Systems Reform Taskforce
announced on 27 December 2011 that in light of ‘the Electric Power Market lacking
depth and difficult to utilise in terms of capacity’ there is ‘a necessity to invigorate
competition throughout the Electric Power Trade Market’.
Gas
With respect to gas, no particularly noteworthy market developments are currently
anticipated or under consideration.
V
RENEWABLE ENERGY AND CONSERVATION
i Electricity
The Renewable Electric Energy Act
Japan was subject to a huge development in the area of renewable energy in the past year.
The Act on Special Measures concerning the Procurement of Renewable Electric Energy
by Operators of Electric Utilities (‘the Renewable Electric Energy Act’) was enacted with
the objective of introducing FITs (a system whereby the total volume of electric power
is bought back at a fixed price). The Renewable Electric Energy Act was enacted on 26
August 2011 and promulgated on 30 August 2011. It will be effective as of 1 July 2012.
The major requirements of the Renewable Electric Energy Act can be summarised
as follows:
a General electric utilities, specified electric utilities and PPSs are expected to become
providers of renewable electric energy and as such must execute all applications
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b
c
d
e
for contracts for sale of electric power submitted to them by renewable electric
energy suppliers and facilitate the connection of the power generating facilities of
such suppliers to their own electric facilities for transformation, transmission and
distribution of electric power.
Renewable electric energy is defined as electric power obtained and converted
through the use of electric transduction facilities from renewable energy sources
such as solar, wind, water (currently statutorily limited only to small and medium
hydroelectric generators with output of less than 30,000kW), geothermal,
biomass and other sources as stipulated in the relevant cabinet order.
Sales prices and contract terms shall be as set by the METI upon the input of the
Committee for Calculation of Procurement Cost and Related Matters.
In order to be eligible for the above benefits, renewable electric energy suppliers
are required to acquire certification from the METI for their power-generating
facilities.
All transactional costs will ultimately be borne by the electric power consumers
(both private and corporate).
Sales prices and contract terms
Based on the METI’s Overview of the Act on Special Measures concerning the
Procurement of Renewable Electric Energy by Operators of Electric Utilities, 4 published
after the Cabinet’s enactment of the Renewable Energy Act, renewable energy other
than solar power is expected to be charged at a rate ranging from ¥15 per kW to ¥20
per kW for terms ranging from 15 to 20 years. As for solar power, in consideration of
the previous FIT, prices are expected to be approximately ¥40 per kW with terms of
10 years for residential users and 15 to 20 years for all other users. Notwithstanding
the foregoing, however, even though expected figures regarding prices and terms have
already been published, the actual final figures have not yet been officially announced. As
the provisions on sales price and contract terms are still scheduled to be subject to public
comment no later than one month before the Renewable Energy Act is set to take effect,
official announcements in this regard can be expected around late May.
ii Gas
In terms of gas-related renewable energy, biogas has been generating a lot of attention in
recent years. Biogas is a flammable gas produced by the fermentation of organic waste
such as raw sewage, food waste and livestock excretions, a feature that allows it to be
harvested at sewage treatment plants, food factories and other such locations. Major town
gas utilities like Tokyo Gas and Osaka Gas have in recent years established guidelines for
and promoted the purchase of biogas.
4 Available at www.meti.go.jp/press/20110311003/20110311003-3.pdf.
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VI
THE YEAR IN REVIEW
As previously noted, gas industry regulations have not been subject to any substantial
changes in recent years. On the other hand, the electric power industry regulations have,
following the events at Fukushima in 2011, witnessed great reforms such as revisions for
the integration of a single system for the production and transmission of electric power
and the introduction of FITs. It is considered that these reforms are likely to encourage
the emergence of new entrants to the energy industry and merit attention in light of
potential future developments arising.
VII
CONCLUSIONS and OUTLOOK
The events at Fukushima in 2011 served as the main catalyst for the reforms that the
electric power industry has recently been facing. The full extent of these reforms and their
effects, however, remain to be seen. In the meantime, the industry awaits the suspension
of all nuclear power stations in Japan by May 2012, due to growing public and political
sentiment as a result of the accident, an occurrence that is likely to result in further power
shortages this summer.
Under these circumstances, Japan will become increasing reliant on its remaining
sources of energy, that is, oil and liquefied natural gas (LNG). These traditional sources
of fuel are regarded as more stable and reliable; however, because they are ultimately nonrenewable
resources, this in and of itself introduces an entirely different set of issues. At
the end of the day, Japan’s energy requirements may push it in the direction of renewable
energy such as those discussed above. The output of such energy sources is, however,
substantially smaller compared with nuclear energy, not to mention inherently unstable
and less reliable. Accordingly, Japan’s demand for alternative and reliable sources of
energy may even result in renewed interest in the gas industry, which in turn will surely
lead to further developments in this field.
With both the rapidly shifting facets of the energy industry and the unstable
political climate currently looming over Japan’s Diet at the moment, the only thing that
can be said with any certainty is that change is imminent. Exactly how and in what form
such change will take place remains to be seen and it is certainly worth keeping a close
eye on Japan in the years to come.
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Chapter 14
Malaysia
Lukman Sheriff Alias 1
I
OVERVIEW
The energy industry in Malaysia has seen a flurry of major developments and exhilarating
activity in recent years, and this trend is expected to continue in the coming year; 2011
and 2012 will in fact be etched in history as landmark years for the local energy industry.
During the past year, Malaysia has witnessed the award and execution of three power
purchase agreements with an aggregate capacity of 4,400MW, including the conclusion
of the long and protracted negotiations for the purchase of electricity from the
2,400MW Bakun dam generating facility in Sarawak. Also for the first time, the manner
of awarding power projects was undertaken by the Energy Commission of Malaysia
through a bidding process. This is in stark contrast with the previous arrangement of
direct negotiations between Tenaga Nasional Berhad (‘TNB’) and independent power
purchasers. TNB is a privatised national utility and is currently listed on Bursa Malaysia.
In addition to the foregoing, there were momentous developments in the area
of renewable energy industry. A new regulator, the Sustainable Energy Development
Authority, was established. Two new laws came into force: the Sustainable Energy
Development Authority Act 2011 (Act 726) on 1 September 2011, and the Renewable
Energy Act 2011 (Act 725) on 1 December 2011.
For reference, the energy industry referred to in this chapter is confined to the
electricity supply industry.
The regulatory regime for the supply of electricity in Malaysia may be divided
into two. The first is the primary regulatory regime applicable to the whole of Malaysia,
except for Sarawak, which is a state in East Malaysia. The Energy Commission of
Malaysia is the regulator. The other regulatory regime is applicable exclusively to the
supply of electricity in Sarawak. The Director of Electricity Supply is the regulator for
the industry in Sarawak.
1 Lukman Sheriff Alias is a partner at Zul Rafique & Partners.
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II
REGULATION
i
The regulators
Malaysia
The Energy Commission or is a statutory body established under the Energy Commission
Act 2001 (Act 610) to regulate the activities of energy supply in Malaysia and to enforce
energy supply laws. It regulates activities relating to supply and use of electricity including
the generation, transmission and distribution of electricity supply and also those relating
to the supply and use of gas including the delivery, transportation, distribution and
reticulation of gas supply. The Energy Commission, however, does not regulate activities
pertaining to petroleum development activities, which include upstream gas exploration
and mining, which are governed by other laws including the Petroleum Mining Act 1966
(Act 95).
The relevant laws under its jurisdiction comprise of laws not only relating to
electricity supply law as enumerated below, but also the following:
a the Gas Supply Act 1993 (Amendment) 2001;
b the Gas Supply Regulations 1997 (Amendment) 2000; and
c the Gas Supply (Compoundable Offences) Order 2006.
The Energy Commission comprises 11 members and is currently headed by Tan Sri
Datuk Dr Ahmad Tajuddin Ali, who was previously the chief executive officer of TNB.
Although the Energy Commission Act 2001 expressly covers the whole of
Malaysia, by virtue of the Suspension of the Operation of the Act (Sarawak) Order 2001,
the operation of the Energy Commission Act is suspended for the state of Sarawak.
Sarawak
The regulator for the supply of electricity in Sarawak is the Director of the Electricity
Supply. This position was created pursuant to the provisions of the Sarawak Electricity
Ordinance (Chapter 50 – Revised 2002). The Director of Electricity Supply heads the
Electrical Inspectorate Unit (‘the EIU’) under the Ministry of Public Utilities in Sarawak.
The functions of the EIU are to:
a advise the Sarawak government on the policy and direction with regard to the
planning and development for an adequate, reliable, efficient, affordable and safe
power system in the state;
b monitor the technical performance of the industry in general and licensees in
particular to ensure technical compliances and public safety; and
c provide an environment that encourages continued investment in the sector,
efficiency improvement and to protect consumer interests.
The Electrical Inspectorate Unit is also responsible for the following matters:
a licensing of electricity generation and supply;
b registration of electrical installations;
c registration of electrical contractors;
d issuance of certificate of competence for competent persons;
e establishment of technical and safety standards, monitoring performance and
enforcing compliance;
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f
g
h
safety of electrical equipment and appliances;
accidents notification and investigations; and
technical and economic regulation of the planning, development and operation
of the power grid system.
ii Regulated activities
Malaysia
The relevant laws relating to the supply of electricity in Malaysia are as follows:
a Electricity Supply Act 1990 (Amendment) 2001;
b Licensee Supply Regulations 1990 (Amendment) 2002;
c Electricity Regulations 1994 (Amendment) 2003;
d Electricity Supply (Compounding of Offences) Regulations 2001; and
e Efficient Management of Electrical Energy Regulations 2008.
The primary source of law is the Electricity Supply Act 1990 (Act 447) (‘the ESA’). It
provides regulation for the supply of electricity, licensing of any electrical installation,
the control of any electrical installation, plant and equipment, the safety of persons using
such installation and the efficient use of electricity. This is provided in the preamble to
the ESA.
Under the ESA, no person can use or operate any electrical installation or supply
energy from such installation to any person without obtaining the required licence from
the Commission. In essence, any company seeking to either undertake the generation,
transmission or distribution of electricity would thus have to obtain a licence from the
Energy Commission.
Another important aspect of the ESA is the control of the tariff chargeable by
licensees. Under the ESA, any levy or tariff imposed must obtain the prior written
approval in writing by the Minister and so requires the decision of the Cabinet. In
addition, the ESA also sets out the provisions on the requirement of competent persons
to operate electrical installations and stipulates the duties and obligations incumbent on
licensees.
Sarawak
The legal framework for the supply of electricity industry in Sarawak comprises the
following laws:
a the Electricity Ordinance (Chapter 50 – Revised 2002);
b the Electricity (Amendment) Ordinance 2003 (Chapter A109);
c the Electricity Rules1999; and
d the Electricity (State Grid Code) Rules 2003.
The primary source of law in Sarawak for electricity supply is the Electricity Ordinance
as amended by the Electricity (Amendment) Ordinance 2003.
The Energy Ordinance prohibits any person from using and operating any
electricity installation, the supply, distribution and transmission of energy from such an
installation and the establishment of any installation or power generating plant without
obtaining a licence from the Sarawak state government represented by the head of state,
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Yang DiPertuaNegeri. Thus, any company seeking to either undertake the generation,
transmission or distribution of electricity would have to obtain a licence from the state.
Any tariff charged by the licensee must be approved by the state government.
The Electricity Ordinance also stipulates that the Minister may also set out a maximum
price for the reselling of energy by a licensee to consumers. Apart from the foregoing,
the Electricity Ordinance sets out provisions on the requirements of competent person
to operate electrical installations and stipulates the duties and obligations incumbent on
licensees.
iii Ownership and market access restrictions
Malaysia
At the time of writing, only TNB has been awarded transmission and distribution
licences for the whole of Malaysia except for the states of Sabah and Sarawak. 2 The
government and Energy Commission have, however, awarded the generation licences to
a number of independent power-producing companies other than TNB.
For the state of Sabah, Syarikat Electricity Sdn Bhd (‘the SESB’) is the sole
transmission and distribution licence holder. Similar to peninsular Malaysia, generating
licences have been awarded to SESB and a few other independent power-producing
companies.
There is no restriction in law restricting the ownership of the licences; however,
approvals normally contain restrictions on ownership pertaining to Malaysian and
bumiputera shareholdings.
Sarawak
The sole transmission and distribution licence in Sarawak is granted to Syarikat Sesco
Berhad (referred to as ‘SESCO’) which is the privatised entity of Sarawak Electricity
Supply Corporation. It is a wholly owned subsidiary of Sarawak Energy Berhad (referred
to as ‘SEB’) which is owned in majority by the Sarawak state government. The generating
licenses have been granted to SESCO and subsidiaries of SEB.
iv Transfers of control and assignments
Under the ESA in Malaysia, licences cannot be transferred without the approval of the
Minister. Under the Ordinance in Sarawak, licences cannot be assigned or transferred in
any manner without the approval of the state government.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
The transmission and distribution network in Malaysia has not been unbundled and
in essence can be divided into three parts. One is peninsular Malaysia’s distribution
2 Distribution licences are awarded by the Energy Commission in peninsular Malaysia for the
supply of electricity within a private area or within a franchise area such as within a port or
industrial area.
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network, which is wholly owned, controlled and operated by TNB, except in certain
privatised or franchise areas. The other is the Sabah network, which is owned, controlled
and operated by the SESB and the third is the Sarawak network, owned, controlled
and operated by SESCO. As a result, Malaysia has three grid codes: the Malaysian Grid
Code, the Labuan and Sabah Grid Codes, and the Sarawak Grid Code. In addition, there
is a Malaysian Distribution Code.
IV
ENERGY MARKETS
i Development of energy markets
There is no wholesale electricity market in Malaysia. It has only liberalised certain parts
of the generation market and even then the supply of electricity from TNB, SESB and
SESCO forms the main portion of the supply chain. Each generation company enters
into a power purchase agreement expressly stipulating the manner of supply of electricity
to the grid. The grid system operator determines the order of priority for despatch of the
plant.
ii Energy market rules and regulation
There have been no new market rules and regulations for the past year except for the new
laws and regulations on renewable energy, which will be discussed in Section V, infra.
iii Contracts for sale of energy
Three major power purchase agreements were executed or awarded in the past year,
the largest being the purchase of electricity by Sarawak Energy Berhad from Sarawak
Hidro Sdn Bhd’s Bakun hydroelectric generating facility, which has a nominal capacity
of 2,400MW.
The second power project was awarded to TNB’s wholly owned subsidiary, TNB
Janamanjung and the third to Malakoff Berhad. Both plants are coal-fired plants, each
with a nominal generating capacity of 1,000MW. For the latter two projects, the Energy
Commission for the first time carried out a tender process.
iv Market developments
There has been a hive of activity in the energy market for the past year, mainly due to
the ambitious plans of Sarawak to turn itself into a power-producing state, meeting the
electricity demand in the peninsular Malaysia.
For the past few years, the state of Sarawak has embarked on a massive regional
development known as the Sarawak Corridor of Renewable Energy (‘SCORE’). Under
SCORE, the state had planned to produce of up to 28,000MW of electricity to supply
to various new high electricity consumption industries in Sarawak. The plan was to have
a mixture of 20,000MW energy from hydroelectric generating facilities, 5,000MW from
coal-fired plants and 3,000MW from other types of generating plant. Electricity from
the Bakun 2,400MW generating facility forms part of the supply chain under SCORE.
Apart from the Bakun dam, the Murum hydroelectric dam is expected to be completed
by end of 2013, adding another additional installed capacity of 944MW. It was also
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reported that by this year, the SEB will commence construction of a new 600MW coalfired
power station in Balingian, Sarawak. On the offtake side, to date, the SEB has
entered into two power purchase agreements to supply a combined 570MW for two
new manganese and ferrosilicon alloy smelting plants in Sarawak. It is also aggressively
pursuing other buyers and is shortly expected to sign two power purchase agreements to
supply two new polycrystalline silicon plant and aluminium smelting plans in Sarawak.
The Bakun dam was initially built to meet the demand for electricity in peninsular
Malaysia. With the Bakun dam, however, being determined by the federal and Sarawak
state governments to be part of SCORE in the past year, the Energy Commission had
to undertake to develop new power projects on a fast-track basis in peninsular Malaysia
to replace such supply. Thus it had tendered out and awarded two coal-fired power plant
projects to TNB Janamanjung and Malakoff.
V
RENEWABLE ENERGY AND CONSERVATION
The past year has been a landmark period for renewable energy. Two significant laws were
passed by the Malaysian parliament, which paved the way for greater development in the
field of renewable energy. One is the enactment of the Sustainable Energy Development
Authority Act 2011 (Act 726), and other is the Renewable Energy Act 2011 (Act 725).
The new regulator for renewable energy is the Sustainable Energy Development
Authority (‘the SEDA’) that was established under the Sustainable Energy Development
Authority Act 2011 (Act 726). Its functions include:
a advising the government on all matters relating to sustainable energy including
recommending policies and laws on sustainable energy;
b implementing and managing the feed-in tariff system;
c implementing sustainable energy laws; and
d promoting and developing sustainable energy.
The laws pertaining to renewable energy are as follows:
a Renewable Energy Act 2011 ( Act 725);
b Renewable Energy (Criteria for renewable resources) Regulations 2011;
c Renewable Energy (Allocation from Electricity Tariffs ) Order 2011;
d Renewable Tariff (Feed-In- Approval and Feed-In-Tariff Rate) Rules 2011;
e Renewable Energy (Renewable Energy Power Purchase Agreement) Rules 2011;
f Renewable Energy (Technical and Operational Requirements) Rules 2011;
g Renewable Energy (Recovery Of Moneys by Distribution Licensee) Rules 2011;
and
h Renewable Energy (Administrative Fees) Order 2011.
The primary law is the Renewable Energy Act 2011, which establishes the feed-in tariff
system that sets up the following framework:
a the connection of supply line for the distribution of renewable energy;
b the priority of purchase and distribution; and
c the feed-in-tariff rates.
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Any person who wants to generate renewable energy must first obtain approval from
SEDA. The maximum permitted generating capacity for each renewable energy
installation is no more than 30MW unless the government approves otherwise.
Under the Renewable Energy Act, only the following renewable resources are
recognised, namely biogas, biomass, small hydropower (not exceeding 30MW) and solar
photovoltaic. As such, other renewable resources such as those from wind or wave farms
are currently not covered by the current feed-in tariff system.
The Renewable Energy Act provides a standard form of renewable power purchase
agreement which is to be entered by the parties as prescribed by SEDA. It also sets out
the terms of priority purchased which puts an obligation on the distribution licensee
to purchase renewable energy in priority of other non-renewable sources of energy. The
only exception to this rule is when SEDA grants an exemption on the ground of public
and private safety.
The feed-in tariff mechanism under the Act provides various tariff rates and
periods for different renewable resources. The tariff mechanism also takes into account
different technologies and materials used by providing differing rates. It is to be noted
that there are also provisions for a fixed annual regression rate of the feed-in-tariff rate.
SEDA has further a right to review and revise the regression rate every three years;
however, the Renewable Energy Act provides that such review must take into account,
inter alia, the ability of feed-in tariff approval holders to recover their initial cost and to
achieve satisfactory returns within a reasonable time scale.
In addition to the foregoing, the Renewable Energy Act further provides provisions
for technical and operational requirements. Assignment and transfer of feed-in tariff
approvals can only be made upon obtaining approval of SEDA.
VI
THE YEAR IN REVIEW
The past year has seen a flurry of major developments and activities in the energy industry
in Malaysia. Three major power purchase agreements with a total combined nominal
capacity of 4,400MW have been executed or awarded in the past year. Unlike in previous
years, the Energy Commission awarded the last two power projects on a tender basis.
The past year also saw a major structural change in the energy industry with the passing
of a new law on renewable energy and the setting up of a new independent commission
on renewable energy. This trend is expected to continue with more power projects being
introduced to replace the decommissioned first batch of power plants. In the renewable
energy sector, more projects are expected to be awarded to meet the goal for a more
sustainable electricity supply.
The past year has also seen the curtailment of gas supplied to gas-fired plants.
Petronas has been the sole supplier of gas for the gas-fired plants and is facing a depleting
supply of gas sourced locally. As such, it has built a major gas regasification plant to
overcome the demand but is using imported gas. For the past few decades, Petronas
has subsidised the price of gas supplied to the energy industry; however, with gas being
imported, it no longer wishes to subsidise the cost. This issue became the focus at the
end of 2011.
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Malaysia
All power purchase agreements entered into by TNB with other independent
power producers are based on a gas pass-through model; as a result TNB bears the cost
of any fuel increase. It should also be borne in mind that TNB is not able to increase the
electricity tariff without the government’s approval. Thus, there was a mismatch resulting
in a loss for TNB in 2011. The government, the Energy Commission, Petronas and TNB
had to resolve this and agreed that TNB will only bear certain parts of the increased
cost of fuel. However, at the time of writing, it is unclear whether this arrangement is a
permanent one, and will apply in future.
VII
CONCLUSIONS and OUTLOOK
The precedent of open bidding for power projects by the Energy Commission is set
to continue in the near future. The current tender for the Prai power project is an
apt illustration. The Prai power project is a 1,000–1,400MW gas-fired plant project
located in Penang to replace an existing expiring gas-fired generating facility. The Energy
Commission invited between 33 and 38 companies to bid, and 18 companies and
consortium submitted their bids. Currently the Energy Commission has prequalified
the bids to nine parties including five consortia of local and foreign companies and
four solely local companies who have existing power plants. It would be an interesting
development if the award were to be given to a consortium including a foreign company
as the prevalent practice is to award to local companies. If such is the case, it would be a
further step in liberalising the ownership requirement in generating facilities in Malaysia.
The Prai power project also reflects the increasing trend of activities in the energy
market in Malaysia. Malaysia would need around 4,500MW of newly installed capacity
by 2016 and 2017. This is to replace 4,105MW of first-generation capacity supplied by
independent power producers of the first generation since the 1980s such as YTL Power
International Bhd and Genting Sanyen, which will expire between 2015 and 2017.
Out of 4,500MW, about 3,500MW will be needed to replace retiring capacity,
while the remaining 1,000MW is additional capacity for future use. From the 3,500MW
of power being offered for tenders, 1,400MW are for gas-fired plants while the remaining
2,100MW can be for new combined-cycle or coal-fired power plants. The above
essentially sums up the outlook of the Malaysian energy industry.
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Chapter 15
Mexico
Gonzalo A Vargas 1
I
OVERVIEW
Through a Constitutional directive set out in Article 27, in Mexico the generation,
distribution and transportation of energy is reserved to the Mexican state, which
created the Federal Electricity Commission (‘the CFE’). For 75 years, this agency was
responsible for designing and developing the required infrastructure for the generation
and distribution of energy. Since the 1982 amendment to the Law of the Public Service
of Electric Energy (‘the Electric Energy Law’), which allowed, under limited schemes,
the participation of the private sector in the generation of energy, private companies
slowly started to participate under the available schemes, but the CFE has remained as
the cornerstone of the sector, given that not only did it retain ownership of producing
plants, but also the distribution network and the exclusive rights to transfer energy. The
applicable regulatory legal framework has been further enhanced with a view to creating
more equitable grounds for different participants in the field, and diminishing the
discretionary powers of the CFE, thus allowing it to maintain its plants and transmission
network, but at the same time incentivising further private-sector participation.
II
REGULATION
i The regulators
The main authority in charge of regulating all matters related to the energy sector is
the Ministry of Energy, with the active participation of two entities with administrative
independence from the Ministry of Energy, the Regulatory Energy Commission (‘the
CRE’) and the National Hydrocarbons Commission (‘the CNH’).
1 Gonzalo A Vargas is a partner at González Calvillo, SC.
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Mexico
The CRE is responsible for regulating all matters related to private energy
production, transportation and first-hand sale to private parties, 2 except for the
exploitation and extraction of hydrocarbons, as well as its shipment and storage, which
falls under the competence of the CNH. Mexican law specifies that refined hydrocarbons
and gas extracted from ground deposits of mineral carbon, as well as the first-hand sales
to private parties, shipment, storage and distribution of basic petrochemicals that can
be used as raw materials for industrial production do not fall within the purview of the
CNH, the CRE thus being the competent regulatory authority.
The CRE is entitled to:
a participate in the determination of the tariff for the distribution, transmission
and delivery of electricity;
b approve and establish the terms and conditions for the first-hand sale to private
parties, shipments, storage and distribution of gas, oil, products obtained from oil
refining, basic petrochemicals and bioenergetics;
c grant and revoke permits and licences to carry out all the activities that are
regulated by the CRE; and
d impose fines to individuals or entities that produce, export or import electricity
without the proper permits or licences.
Since the exploitation and extraction of hydrocarbons are activities reserved to the
Mexican government, the regulatory function of the CNH does not encompass any
activity carried out by private parties. Its functions make it the supervisory and advisory
authority for Mexican public entities in charge of the exploitation and extraction of
hydrocarbons as provided by Article 27 of the Constitution. Its role includes establishing
technical guidelines for the exploration and exploitation of hydrocarbons, reviewing
and opining on hydrocarbon exploitation and exploration projects, and establishing
methodologies to evaluate the efficiency of such exploitation and exploration.
In terms of regulating bioenergetics, there is an interministerial commission,
the Inter-Ministerial Commission for the Development of Bioenergetics, formed by six
State Secretaries. This agency is responsible for defining the policy applicable to the
production, commercialisation and use of bioenergetics.
All bioenergetics permits and licences are granted by the Ministry of Energy,
and in cases when bioenergetics are to be produced from corn as its raw material, and
such corn is cropped in Mexico, an additional licence from the Ministry of Agriculture,
Livestock, Rural Development, Fisheries and Food (‘SAGARPA’) is required.
The current main sources of legislation in the energy sector are the Law Regulating
Constitutional Article 27 on the Oil Sector, the Electric Energy Law, the Law on the
Promotion and Development of Bioenergetics and the Law on the Use of Renewable
2 Through the concept of ‘first-hand sale to private parties’ Mexican law sets a legal shield for
Petroleos Mexicano (‘Pemex’), the state-owned petroleum company, so that it can carry out any
activities of transportation, distribution, storage and production of chemical products derived
from hydrocarbons, subject only to its own laws and regulations but without having to apply
for permits from the CRE, until the first sale of products is made to a private party.
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Mexico
Energy and Energy Transition Financing (‘the Renewable Energy Law’). The Mexican
Congress also enacted the Law of the CRE and the Law of the CNH, which establish the
scope of authority and internal organisation of each of these regulatory entities.
The executive branch has the power to issue the regulations on the laws approved
by the Mexican Congress and has thereupon issued regulations dealing with oil, natural
gas, LP gas, electric energy and renewable energy.
In addition, the CRE and the CNH are entitled to issue rules, manuals and
directives regarding matters on which they are competent to rule.
ii Regulated activities
Mexico has a closed market regulation regarding the exploitation and extraction of oil,
gas that does not come from mineral beds or reservoirs, and the different raw materials
that are deemed as basic petrochemicals (ethane, propane, butane, pentanes, hexane,
heptane and naphtha), whose extraction or production, transportation, storage, and
‘first-hand sale’ to private parties can only be carried out by the Mexican government
through subsidiaries of Pemex. Nuclear energy generation is also exclusively reserved to
the Mexican government.
The transportation, storage and supply of natural gas and liquefied petroleum gas,
as well as the production, storage and distribution of biogas, biodiesel, bioethanol or any
other bioenergetics, are regulated activities that can be carried out by private parties after
obtaining permits from the CRE.
As the Mexican Constitution deems the production and distribution of electricity
a public service that must be guaranteed to the population in general, it provides for
a state monopoly. The CFE is the public entity in charge of producing and providing
electric power throughout Mexico.
Notwithstanding the foregoing, as a result of the North America Free Trade
Agreement (NAFTA), the Mexican government amended the Electric Energy Law to
enable private participation in the production of electricity. Such amendment was,
however, focused on enabling private parties to produce electricity for self-consumption
or for its distribution to the CFE. For that purpose, the amendment to such law included
four basic new production schemes which allowed private participation:
a Independent production: private parties produce electricity and must distribute
all their power output to the CFE. In this case, the licence to be granted is subject
to a public bidding process in which technical requirements need to be met, and
price is a determining factor.
b Self-supply: private parties can generate electricity for their own consumption.
Likewise, various consumers can acquire electricity if they acquire an interest in
the producing entity;
c Cogeneration: cogeneration companies will own private facilities intended to
produce electricity to be supplied to private entities or individual establishments
associated with the cogeneration company.
d Small-scale production: private parties produce electricity with a capacity no
more than 30MW, for the sole purpose of supplying their power output to CFE.
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Mexico
Furthermore, private parties are also able to import and export electricity when
importation is done only for self-consumption while exportation may be made under
any of the previous production schemes.
A permit granted by the CRE is required to operate electricity production facilities
under any of these production schemes, as well as for the importation or exportation of
electricity as set out in the Electric Energy Law. During the permit granting analysis
process, the CFE may opine on the granting or denial of the permit.
In all cases, irrespective of the type of activity to be developed, the process to
obtain a permit from the CRE consists mainly of the submittance of an application
containing legal, technical and financial information of the company and the project,
demonstrating its experience and proficiency to carry out the activity. Although the legal
provisions establish a period of between three and four months for the analysis of the
application and issuance of the permit (or denial of it, as the case may be), in practice it
usually takes around six months from the application filing date.
Regarding the permit granted by SAGARPA for the production of bioenergetics
using corn as raw material, after submission of the application SAGARPA has 15 business
days to issue the permit. Thereafter, an application must be submitted to the Ministry
of Energy for the production of bioenergetics, attaching a copy of all the environmental
licences required for the project and the permit granted by SAGARPA. The Ministry of
Energy then has 30 business days to deny the issuance of the permit, otherwise it will be
deemed granted. Such permit will be in force for 30 years from its issuance date.
iii Ownership and market access restrictions
In the past, the Mexican regulatory system excluded foreign investors from participating
in sensitive areas such as electricity production and hydrocarbon extraction and
exploitation. Throughout the past two decades, the Mexican government’s position
has gradually changed, allowing the participation of foreign investors in such areas.
Currently, foreign investors can fully participate in the same activities as Mexican citizens
or companies, except for three specific cases: (1) gasoline retailing and LP distribution;
(2) construction of pipelines for the transportation of oil and its derivative products; and
(3) oil and gas drilling.
In the first case, only Mexican individuals or companies with a foreigners exclusion
clause in their by-laws can carry out gasoline retailing and LP gas distribution activities.
In the second and third cases, the Foreign Investment Law states that for the
construction of pipelines for transportation of oil and its derivatives, and for oil and gas
drilling, an authorisation from the Ministry of Economy must be obtained when foreign
investors hold more than 49 per cent of the corporate capital of the company developing
such activities.
In the event of the acquisition of assets for the production of electricity, the
distribution of LP gas or natural gas, or generally any activity related to the energy
market, it is likely that the related transaction surpasses the thresholds established by
the Federal Law on Economic Competition and so will need the approval of the Federal
Competition Commission (‘COFECO’) to be able to accomplish such transaction that
may be deemed a concentration.
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Mexico
Environmental licences are needed in order to install facilities for the production
of electricity and bioenergetics, as well as for the transportation and storage of natural
gas, LP gas and bioenergetics, since environmental risks can arise from such activities.
Environmental licences are commonly granted by local and federal authorities, depending
on the activity to be carried out (construction or operation), and they are typically
regarded as sensitive items to consider and deal with. As part of a legal due diligence, an
environmental expert may have to address social issues with adjacent communities.
At a federal level, such environmental licences may be environmental impact
authorisations (whose application process lasts about 60 business days), risk authorisations
(whose application process lasts about 45 business days), and air emissions permits,
known in Mexico as ‘Comprehensive Environmental Licences’ (whose application
process lasts about 30 business days). These licences are requested from the Ministry of
Environmental and Natural Resources. At the state or municipal levels of government,
common approvals include land use licences (or in the case of transmission lines or
pipelines a route-tracing approval) and construction licence whose issuance time frames
vary depending on the state or municipality, but are usually granted within one month
of the application date.
Finally, authorisations from the applicable governmental agency (municipal, state
or federal) must be obtained if facilities for electricity production and the installation
of trunk lines to transmit the electricity produced to the National Electric System (‘the
SEN’), or the transportation of gas through pipelines is done via rivers, lakes, crossing
land or any land of governmental ownership.
iv Transfer of control and assignments
To convey assets or for the assignment of permits for the production of electricity,
transportation or distribution of natural gas, as well as for the merger and acquisition of
companies developing such activities, the relevant authorities reviewing such transactions
and authorising or rejecting the same, are the CRE and, if applicable, the COFECO.
The Electric Energy Law states that when the ownership of private production
energy facilities is sold, the permit for the production of energy can only be assigned to
the new owner of the facilities, therefore the assignment of the facilities is always linked
to the assignment of the production permit.
For the assignment of the aforementioned permits and production facilities, an
assignment application to the CRE is required. In the same way, legal, technical and
financial information of the assignee must be submitted. If the CRE considers that the
information demonstrates the economic and technical capability of the assignee to carry
out the production of energy, it will authorise the assignment within a month of the
filing being made.
In the case of assignment of the transportation, storage or distribution of natural
gas permits, the procedure and period of analysis by the CRE of the assignment request is
similar to the aforementioned, but there is no need to ask for a permit to assign facilities.
Concerning the procedure for the assignment of the permit related to the
transportation, storage or distribution of LP gas, the time frames and relevant authorities
are different from the foregoing cases. If the permit is for the transportation of LP gas on
tankers (ships or trucks), the permit assignment must be requested from the Ministry of
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Mexico
Energy by filing an assignment application and the decision will be rendered within 10
business days. If the permit to be assigned is for the transportation through pipelines and
the storage or distribution of LP gas, the relevant authority is the CRE, which will render
a decision within 140 days of submission.
In all cases, the Law on Economic Competition will be applicable if the thresholds
set out in such law to notify asset concentrations are surpassed.
In the case of permits for the development of activities related to electricity
generation, natural gas and LP gas, COFECO must also render an opinion on the
assignment of permits, as these areas are considered especially sensitive in terms of
competition and market access matters; such opinion will be considered by the CRE
while analysing the assignment application.
III
TRANSMISSION /TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
In previous years, the most significant changes to the gas industry framework were the
publication in the Official Gazette of Official Mexican Standards, of which the most
recent and relevant is the NOM-001-SECRE-2010; this sets out the specifications to
be met by natural gas-handling systems in transportation, storage and distribution of
natural gas, with consumer safety and environmental protection in mind.
As previously indicated, transportation, storage and supply or distribution of
natural gas is carried out by licensed private parties, but generally jointly with Pemex Gas
y Petroquimica Basica (‘PGPB’), a regulated subsidiary of Pemex, the most important
market participant given that it owns the majority of the transportation network,
together with the CFE.
Although under the current law vertical integration is not permitted in the natural
gas market, since the regulations forbid the same company or individual from holding a
permit for both distribution and transportation of natural gas, Pemex (through PGPB) is
the only entity that can legally be vertically integrated, until the first-hand sale to private
parties.
On the electricity market, the CFE is the only entity entitled to carry out the
transmission and distribution of electricity to final consumers through the SEN, which
is also administered by it.
From a technical standpoint, a private company that holds a permit to produce
electric power under the schemes for self-supply and cogeneration may distribute the
electricity to its shareholders, but in reality the electricity produced is output to the SEN,
which will transmit and distribute the electricity to the shareholders or partners of the
producer company for a distribution fee.
ii Transmission/transportation and distribution access
Concerning natural gas, permit beneficiaries or licensees must allow users open access to
their services on a non-discriminatory basis, subject to availability of capacity, technical
feasibility and the execution of a services agreement. Refusal to do so may be notified
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Mexico
to the CRE and the lack of available capacity at the time of denial should be supported.
Payment of connection is agreed between the parties.
Natural gas distributors are bound to extend or enlarge the systems within their
geographical zone at the request of a third party who is not a permit beneficiary, provided
the service is economically feasible. Transporters are bound to extend or enlarge their
systems at the request of a third party provided the service is economically feasible or
parties enter into an agreement to cover the cost of the pipelines or other installations
that constitute the extension or enlargement.
For serving a determined geographical zone, transportation and distribution,
permits may not be issued to one single equity unless there are efficiency and profitability
gains or it becomes necessary due to the lack of transportation infrastructure and there
are no other parties interested in undertaking a natural gas investment project.
iii Rates
The rates and process for the sale, transportation, storage and distribution of natural gas
and LP gas in Mexico are regulated by the CRE.
For the sale, distribution, transportation and storage of natural gas, rates and
prices are determined pursuant to the provisions of the Directive on Rates and Price
Transfer for Natural Gas Activities from 2007, and the Directive on Highest Prices of
Natural Gas on its First Sale to Private Parties from 2009.
Under such legal provisions the price for the first-hand sales to private parties may
be determined considering the following:
a the reference price at the Henry hub (the pricing point for natural gas futures
contracts traded on the New York Mercantile Exchange);
b the difference between the Henry hub price and the price of gas at south Texas,
United States of America; and
c transport costs between the border in Reynosa and pipelines in south Texas, which
are added, subtracted or removed depending on the balance of foreign trade of
natural gas.
The rates for distribution, storage and transportation of natural gas may be different
for each carrier or distributor and are determined by the CRE considering the market
characteristics.
In the case of the rates and prices of the first-hand sale to private parties, sale to
final consumers, storage, distribution and transportation of LP gas, the methodology to
determined them is much more complex than in the case of natural gas, since the CRE
must take into consideration several market variables.
Apart from the special or private schemes of electricity production that the
law allows, the only entity that can produce and sale energy to private individuals or
companies is the CFE; therefore, most of the energy that is supplied and used throughout
Mexico is that supplied directly by the CFE.
Energy tariffs vary depending on whether electricity is used for commercial,
industrial or residential purposes, and also the zone in which the consumer is located, and
is determined, based on proposals made by the CFE, and by the Ministry of Treasury and
Public Credit with the advice of the Ministry of Energy and the Ministry of Economy.
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Mexico
The sale price tariffs for energy sale by private parties to the CFE is determined by
the production scheme to which the private parties are subject to. If they are independent
producers, the tariff is determined by the electricity purchase sale agreements they
execute with the CFE. Otherwise, if private parties produce electricity under the
scheme of cogeneration or self-supply, the sales price can be freely determined between
cogeneration or self-supply companies and their shareholders or associates, while the
excess electricity can be sold to the CFE.
iv Security and technology restrictions
In Mexico security aspects have increased in importance, especially since 2007 when the
government initiated a frontline battle against the drugs cartels, and since then special
laws and provisions have been enacted in order to guarantee security and legal compliance.
As a consequence of such security-strengthening policy, protection of the
infrastructure related to the energy sector is granted by the Article 253 of the Federal
Criminal Code to facilities that carry out the production of electricity and storage of gas
and other hydrocarbons, as well as to pipelines that transport such products, stipulating
as a crime the obstruction of production, transmission or transportation, and to the sale
of electricity, natural gas and LP gas.
Another issue to consider is cybersecurity, which must be analysed from an
infrastructure perspective, as the Federal Criminal Code punishes the destruction of
poles, insulators, wire or machines employed for public telecommunications services,
including any component for the production of magnetic or electromagnetic energy or
means of transmission.
As a general rule there are no restrictions for the transfer of technology. Royalty
payments should meet international transfer-price rules from a tax standpoint.
IV
ENERGY MARKETS
i Development of energy markets
At present there is no organised domestic market for the sale of any type of energy.
Concerning electricity, even when there are regions with different tariffs, given
that the only purchaser of energy is CFE, it is difficult to say that there is a real market.
With respect to natural gas, even though the current legal framework sets the basis
for the creation of a market, a resellers’ market has not yet been created given that current
permit beneficiaries may deny access if they support the fact that access is not technically
or economically feasible.
ii Contracts for the sale of energy
Market participants may enter into individual contracts for the sale of natural gas.
Natural gas service providers may stipulate maximum charges, and the parties may freely
agree on a price different from the maximum charge for a determined service, provided
the agreed amount is no lower than the variable cost of providing the service. Charges
made by a permit beneficiary may not be unduly discriminatory or be conditional on the
rendering of other services.
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Market developments
Mexico
It is considered that when the offer of renewable energy sources reaches a 10 per cent of
total availability, there will be basis for the creation of a market.
V
RENEWABLE ENERGY AND CONSERVATION
i
Development of renewable energy
Along with the enactment of the Renewable Energy Law in 2008, in recent years Mexican
federal and local governments have developed a wide variety of programmes and benefits
related to the development of renewable energy.
The Renewable Energy Law seeks to foster programmes, activities and projects
aimed at achieving a larger use of renewable energy sources and clean technologies. It
also affords an important right to renewable self-supply energy producers of less than
0.5MW to have unrestricted access to the energy bank of CFE, thereby being able to
make ‘deposits’ and ‘recoveries’ of the electricity produced for the purpose of promoting
investment in this area.
This energy bank was created in 2001 by the CRE when it realised that any
renewable energy production project was not capable of being developed if no system
existed to guarantee energy producers, especially self-suppliers; they can can ‘deposit’
their energy in a system that will allow them to ‘recover’ it when their production does
not satisfy their demand.
Another important programme to promote investment by private companies
in renewable energies is, at the federal level, accelerated tax deductions for companies
investing in equipment employing solar energy or generally using clean technologies.
Similarly, the Mexican federal government has implemented different types
of economic benefit to livestock farmers in order to reuse organic waste produced by
animals to produce energy by means of the installation of biodigesters on the farms;
likewise, there have been efforts to produce energy based on all waste collected from
deposits.
In recent years the federal government determined that within Mexico there was
potential for the production of energy by wind farms equal to 11,000MW; consequently,
it instructed the CFE to plan the installation of new wind farms to guarantee the energy
supply in the south east and north west of Mexico. These projects (Rumorosa I, II and
III, located at Baja California; Oaxaca I, II, III and IV, Sureste I, II, III and IV and La
Venta III, all located at Oaxaca) will jointly generate 1,216MW. Some of these projects
have been supported with contributions from the World Bank not only of financing
but of technical assistance for the development of projects and businesses involving
renewable and green energy.
ii Energy efficiency and conservation
Several programmes have been created by the Mexican government aimed at obtaining
a better and more efficient use of energy. Of these, the ones that have had the greatest
impact on energy savings are those aimed at reducing household electricity consumption.
Household consumption represents between the 25 per cent and 27 per cent of the total
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electricity consumption in Mexico and is the sector in which fewer real efforts have been
made to achieve a more efficient use of electricity and other energy products such as gas.
In 2008, the federal government established the National Commission for Energy
Efficiency (CONUEE), an independent entity, part of the Ministry of Energy, that aims
to promote energy efficiency by pursuing the reduction of the amount of energy required
to satisfy energy needs, and ensuring the lessening of negative environmental effects
resulting from the generation, distribution and consumption of energy.
iii Technological development
The technological development is one of the most unsuccessful areas in Mexico, since
the support to technology improvements is generally poor, while the economic support
of the government is insufficient to have real advances in this area.
Concerning ‘smart-grid’ technologies, the CFE has implemented teleprotection
and telecontrol systems that allow increasing safety and real-time operation of the SEN.
In the short term, the CFE is expected to incorporate a massive amount of information
and communication technology into its electric operations.
Old energy consumption meters are being replaced by the CFE by remote reading
systems in different cities as well as in hard-to-reach areas.
VI
THE YEAR IN REVIEW
Since the need to assure a better supply of gas to all parts of Mexico became imminent,
the federal government has been developing a strategy for the construction of new
gas pipelines throughout the country, which will be some of the largest energy-related
projects in recent years.
The CFE has already awarded, after an international public bid, a public service
agreement for the transportation of gas through a pipeline that goes from the state of San
Luis Potosí to the state of Querétaro across the state of Hidalgo, of up to 630 million
cubic feet per day of natural gas. This project is known as Tamazunchale-El Sauz.
It is also expected that during 2012 a call for an international public bid for the
construction of two pipelines – Noroeste and Los Ramones – will be published, the latter
being the most important, as it will have the capability to transport up to 2,000 million
cubic feet per day by pipelines.
After the 2008 oil industry reform, in 2011 Pemex announced the award of several
incentive-based contracts for the exploration and exploitation of mature oil fields along
the Mexican Gulf, pointing out, however, that given the Constitutional restrictions,
these are exclusively services contracts where the Mexican state remains as owner of the
hydrocarbons to be exploited and produced, and that, under the contracts, no rights over
reservoirs or hydrocarbons are granted to the contractor. Contractors would not have the
right to book hydrocarbon reserves.
The first round of incentive-based agreements for the exploration and exploitation
of mature fields was successfully awarded, and a second round is now under way.
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VII
CONCLUSIONS and OUTLOOK
The Mexican legal framework has been transformed in such a manner that the formerly
closed energy regulation scheme has been opened to attract national and foreign investment,
which may improve the development of infrastructure in several energy sectors; this is a
consequence of the anticipated increase in energy demand in the next 10 years.
Some estimates of the Ministry of Energy show that in this period the electricity
demand will increase by 4.8 per cent per year. Hence, the capacity for the production
of energy must increase from 48,769MW in 2006 to 65,055MW in 2016, reflecting an
increase of 16,286MW, which will be obtained by installing new facilities and combinedcycle
power plants, as well as by increasing the usage of carbon and renewable energy
sources of electricity production.
We expect that in coming years, legal amendments will focus on the enlargement
of the fields in which private investors can intervene; the ability of private companies to
directly invest in the exploitation of hydrocarbons and other energy sources and markets
has been a long-running source of controversy, but today it is coming to fruition as its
first results are now becoming visible.
189

Chapter 16
Netherlands
Jan Erik Janssen and Martha Brinkman 1
I
OVERVIEW
The Netherlands has an energy industry with an annual output of between €35 and €40
billion. Specifically, the Netherlands is the largest producer and exporter of gas in the
European Union. Although gas reserves are diminishing, the Netherlands is expected to
maintain its position as a net exporter until around 2025. A contractual arrangement
between the state, Shell and ExxonMobil – often referred to as the ‘gas building’ –
determines that NAM (the Dutch national gas company) is the producer of the vast
Groningen balancing field and that GasTerra is responsible for the sale of that output.
NAM is a 50/50 joint venture between Shell and ExxonMobil and GasTerra a 50/50
joint venture between NAM and the state.
In 2010, 126.6 billion kWh of electricity and 83.9 billion cubic metres of natural
gas were produced in the Netherlands. Due to its natural gas reserves, the Netherlands can
provide for most of its domestic demand for energy and a large portion of its electricity
is produced in gas-fired plants.
The energy markets in the Netherlands have been completely liberalised. Former
regional energy monopolies have been broken up and the largest production and supply
companies are now part of multinationals such as GDF Suez, RWE and Vattenfall. The
bulk of the energy regulation in the Netherlands relates to transmission and distribution
networks.
i Legislative framework
The legislative framework for the energy sector in the Netherlands is largely based on
the European electricity and gas directives. These directives have been implemented in
the Electricity Act 1998 (‘the Electricity Act’) and the Gas Act (together, ‘the Acts’). At
1 Jan Erik Janssen is a partner and Martha Brinkman is a senior associate at Stek.
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the time of writing a bill for the implementation of the European 3rd Energy Package
in the Acts is pending before the Senate. Implementing rules relating primarily to tariffs,
conditions and processes relating to the networks have been laid down in secondary
legislation based on the Acts, such as codes adopted by the Netherlands Competition
Authority (‘the NCA’).
The legal framework for exploration and production activities in the Netherlands
(including the Dutch part of the continental shelf) is laid down in the Mining Act and
secondary legislation – the Mining Decree and Mining Regulation – based thereon.
In addition a Heat Act is expected to enter into force in the foreseeable future that
will give consumers security of supply and will prescribe that the price for the supply of
heat to small-scale users will be set on the basis of the principle that they will not pay
more than consumers connected to the gas network.
II
REGULATION
i The regulators
In the Netherlands there is no separate energy regulator. The regulation of the electricity
and gas markets has been entrusted to the Minister of Economic Affairs, Agriculture
and Innovation (‘the Minister’) and the NCA. The NCA is divided into a number of
departments, including the Office of Energy and Transportation Regulation.
With respect to Dutch energy policy the Minister, by law, must publish an ‘energy
report’ at least every four years, giving guidance on decisions to be taken by the Dutch
government relating to a reliable, sustainable and efficient energy supply. The Minister is
responsible for most of the regulation in the energy sector, including the Acts.
The NCA is responsible for the enforcement of general competition law on the
basis of the Netherlands Competition Act. 2 In its capacity as energy regulator under
the Acts, the NCA adopts the tariff and technical codes governing the transmission and
distribution of electricity and gas. It also sets the regulated tariffs for each distribution
company. The NCA enjoys considerable powers to sanction infringements or violations
of the Acts, including the power to impose administrative fines, a binding order or an
order sanctioned by periodic penalty payments. The NCA is also engaged in handling
complaints about distribution companies and the monitoring of the obligations of
suppliers to so-called small-scale users (consumers and small businesses). From 1 January
2013 the NCA, the Independent Post and Telecommunications Authority and the
Consumer Authority will merge per into one authority: the Netherlands Authority for
Consumers and Markets.
ii Regulated activities
In the Netherlands, network services performed by distribution companies (network
operators) are regulated, whereas other activities have been liberalised.
Pursuant to the Acts, the owner of a transmission or distribution network must
appoint an independent network operator to operate its networks. This operator must
2 See the Netherlands chapter of The Public Competition Enforcement Review (Fourth edition).
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Netherlands
perform its tasks on the basis of regulated tariffs and conditions set by the NCA. TenneT
has been appointed as the operator of the national high-voltage grid (i.e., all grids with a
voltage level of 110kV or more) and GTS (Gas Transport Services) has been appointed as
the operator of the national high-pressure gas network. There are fewer than 10 operators
of regional distribution networks. TenneT and GTS are currently wholly owned by the
Dutch state and the distribution companies are owned by local authorities (provinces and
municipalities). Under strict conditions, an exemption to appoint a network operator for
closed distribution systems may be obtained from the NCA.
Under the Acts, network operators have exclusive powers to construct, maintain,
renew and operate their networks, to provide for connections to their networks and to
provide metering services to small-scale users. The latter is the corollary of the obligation
to roll out ‘smart’ meters to all small-scale users. Small-scale users are defined in the Acts
as users with a connection with a capacity of no more than 3× 80 amperes (Electricity
Act) or 40 cubic metres of gas per hour (Gas Act). Closed distribution systems, electricity
connections with a capacity of more than 10MVA and gas connections with a capacity
of more than 40 cubic metres gas per hour (with the exception of the connecting
point to the network) may be constructed by third parties. The exclusive activities of
the network operators are strictly regulated. The Acts contain various provisions that
ensure the financial and operational independence of the network operators. The Acts
also strictly regulate which activities may or may not be performed by affiliate companies
of the network operator. Pursuant to the Gas Act, an operator must also be appointed
for liquefied natural gas (‘LNG’) and gas storage facilities. These operators enjoy much
lighter regulation.
The supply of electricity and gas in the Netherlands has been fully liberalised
since 2004. Customers are free to chose their supplier and to negotiate the prices for
the supply of electricity and gas. For the supply of electricity and gas to small-scale users
a supply licence from the NCA is, however, required. A licensed supplier is obliged to
supply small-scale users under reasonable conditions. The NCA monitors the small-scale
user supply tariffs and may set a maximum supply tariff when it deems the tariffs too
high, although this has never happened. For the physical trading in electricity and gas
certain requirements of TenneT and GTS must be met.
The Acts do not impose licence requirements on the production of electricity
or gas. The customary permits from local or national governmental authorities under
the applicable planning and environmental legislation are required. For large-scale
investments a coordination mechanism may apply that shortens the overall length of
the procedures. For the exploration and production of oil and gas in the Netherlands
(including the Dutch part of the continental shelf) a licence from the Minister is required
pursuant to the Mining Act. Such a licence will only be granted if the Minister deems
production economically feasible.
For the trade of electricity or gas no licences from the Minister or the NCA are
required. Traders must, however, register with and obtain certain licences from TenneT
or GTS.
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Netherlands
Ownership and market access restrictions
The Acts stipulate that a network or shares in a network operator can only be held by
the state or local authorities (‘the privatisation prohibition’). As previously mentioned,
TenneT and GTS are currently wholly owned by the Dutch state. The Minister has,
however, announced an amendment to the Acts that would allow for a partial privatisation
of TenneT and GTS. The operators of the regional networks must have the economic
ownership of the networks operated by them (and, following an amendment to the
Acts, ownership of the national networks must be with TenneT and GTS or a group
company). In addition, the Acts prescribe that Dutch network operators cannot belong
to a group that produces, supplies or trades energy (‘the group prohibition’; see also
Section III.i, infra).
Except for this group prohibition, the ownership of production, sale and supply
companies is currently not regulated or restricted. The pending implementation of
the European 3rd Energy Package will, however, introduce certain ‘level playing field’
provisions in the Acts. These provisions will entail an obligation to report to the Minister
any change of control over an electricity plant with a nominal capacity of more than
250MW or over an LNG plant. The Minister may then attach conditions to such change
of control if this is deemed necessary for reasons of public safety or security of supply.
Pursuant to the Mining Act, all minerals and gas in or under the Dutch soil
(including the Dutch part of the Continental Shelf) are owned by the Dutch state.
Ownership is transferred to the licensee at the moment of production. The Mining Act
prescribes state participation of 40 per cent via its 100 per cent state-owned participation
vehicle EBN (Energie Beheer Nederland). Licensees must enter into a cooperation
agreement with EBN stipulating the rights, obligations and division of costs in accordance
with the respective interests of the parties.
iv Transfers of control and assignments
Except for the aforementioned ‘privatisation prohibition’, ‘group prohibition’ and ‘level
playing field’ provisions, changes of control over energy companies are not restricted
under the Acts. The NCA has the authority to approve or prohibit mergers or other
changes of control over businesses in the Netherlands under the merger control rules in
the Competition Act (which mirror European merger control rules).
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
The Acts provide for ownership unbundling of network activities. Network operators
may not be part of a group, national or foreign, that produces, supplies or trades
energy. This ‘group prohibition’ is more restrictive than the unbundling requirements
for transmission in the European directives and, moreover, applies to transmission as
well as distribution. The group prohibition has been challenged before the courts. The
largest previously vertically integrated distribution and supply companies, Essent and
Nuon, have not awaited the outcome of this procedure and have sold their production
and supply business to RWE and Vattenfall respectively. The Dutch Supreme Court is
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awaiting the outcome of its recent request for a preliminary ruling to the Court of Justice
of the European Union on the compatibility of the group prohibition with European
law, in particular the principle of the free movement of capital.
The Acts also contain restrictions on network operators that are unbundled from
production and supply companies. These restrictions seek to ensure the organisational
and financial independence of the network operator and to prevent cross-subsidisation
and the dissemination of strategic information. Moreover, the Acts stipulate that the
network operators may only perform their statutory tasks, minimise the outsourcing of
activities by the network operator and restrict the activities that may be performed by the
group to which the network operator belongs to infrastructural activities.
ii Transmission/transportation and distribution access
The Acts provide for a system of regulated third-party access to the transmission and
distribution networks. The network operator must, on request, provide third parties with
a connection to its network (with an exception for large-scale gas users), and, except in
cases of lack of capacity, carry out the transport of electricity or gas against tariffs and
conditions set by the NCA. Oil and gas production pipelines are not subject to thirdparty
access provisions and for LNG and gas storage facilities a lighter regime applies.
Amendments to the Acts that will provide for preferential transportation for
renewable electricity in case of congestion, are expected to enter into force soon.
iii Rates and tariffs
Pursuant to the Acts, the maximum tariffs for the transmission and distribution of
electricity and gas are set by the NCA on the basis of CPI-X pricing. The tariffs are set
annually by the NCA for each individual network operator, based on the previous year’s
tariffs and taking into account changes in the consumer price index and an efficiency
discount (and in the case of the network operators of regional grids, by a factor reflecting
the quality of the grid in terms of outages). The efficiency factor is based on benchmarking
and is set for a period of between three and five years for electricity network operators,
gas network operators as well as the electricity and gas transmission system operators
TenneT and GTS. The regulated rates for metering services to small-scale users are set
separately. The applicable rates for network users are largely determined by the capacity
of their connection.
iv Security and technology restrictions
The Acts currently do not include provisions aimed at protecting homeland security or
the safety of critical infrastructure or systems other than a general obligation for network
operators to operate their networks in a safe and reliable manner. An amendment to
the Acts has been proposed that would give network operators, gas storage companies
and LNG companies a more specific obligation to protect their infrastructure against
terrorism and cyber crime. The details of this obligation will be laid down in secondary
legislation. The Minister will be given the power to give binding instructions in this area.
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IV
ENERGY MARKETS
i
Development of energy markets
The trade and sale of power in the Netherlands takes place on three markets: the overthe-counter
market; the APX-ENDEX physical and futures exchange; and the imbalance
market operated by TenneT. Currently, there are seven electricity interconnectors on
the Dutch border: one with Norway (NorNed), one with the UK (BritNed), three with
Germany and two with Belgium. In addition to the roles of producer, trader or supplier,
a participant on the Dutch electricity market can also be a ‘programme responsible
party’. In that capacity a party must inform TenneT, who balances the system, on a
daily basis of all transactions with other parties which they have planned for the next
day. The difference between the programme and the actual amount of electricity that
has been consumed or supplied is the imbalance for which an imbalance tariff must be
paid to TenneT. Under the Electricity Act, all parties connected to the grid, excluding
small-scale users whose programme responsibility is by law assumed by their suppliers,
bear their own programme responsibility unless they have assigned this responsibility to
a programme responsible party (normally also their supplier).
With respect to gas, GTS offers the title transfer facility (‘TTF’), a virtual trading
place where market parties can transfer gas to another party. GTS registers the title
transfers of gas via the TTF by means of an electronic message that lists the volumes
of gas transferred, the period, and the purchasing and selling parties involved. Delivery
for trades on the physical and futures exchange APX-ENDEX also take place on the
TTF. The high-pressure gas transmission system is connected to Belgium, Germany and
England (BBL). Programme responsible parties (formally knows as ‘shippers’) arrange
for the gas to be transported within the national gas transmission system by contracting
transport capacity with GTS on the basis of the GTS Transmission Service Conditions.
GTS operates the market-based imbalance system.
ii Energy market rules and regulation
There is little red tape involved when it comes to operating on the electricity and gas markets
in the Netherlands. For both electricity and gas, suppliers who supply to small-scale users
must obtain a licence from the NCA and trading on the APX-ENDEX exchange requires
membership thereof. Moreover, programme responsible parties for electricity and gas
must meet the relevant requirements of TenneT and GTS respectively and in order to
participate on the TTF, a party must apply with GTS for a TTF subscription. Following
the entry into force of the Regulation on Energy Market Integrity and Transparency
(REMIT), parties who are active on the wholesale markets for electricity and gas are also
subject to certain information obligations aimed at preventing insider trading.
iii Contracts for sale of energy
Although the retail markets have been liberalised, a licence is required for the supply of
energy to small-scale users. Licensed suppliers are obliged to supply electricity and gas
in a reliable manner and on the basis of reasonable terms and conditions. In practice
all licensed suppliers in the Netherlands use the same general terms and conditions,
which were drafted in cooperation with the Dutch Consumer Union and the NCA.
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In addition, a model contract for the supply of electricity and gas to small-scale users
will be introduced as of 1 July 2012, which all licensed suppliers will be required to
offer in addition to any other type of contract. As of 1 April 2013 the provisions in the
Acts dealing with the ‘supplier model’ for small-scale users will enter into force. Under
this model the licensed supplier will be the primary point of contact for small-scale
users, invoicing for both distribution and supply (the network operator will invoice the
supplier).
Other than for small-scale users, the Acts do not regulate the sale of electricity or
gas. Depending on the type of contract, the Markets in Financial Instruments Directive
(MiFID) as implemented in the Dutch Act on Financial Supervision (‘the Wft’) may be
relevant. Certain types of contracts that qualify as derivatives may qualify as ‘financial
instruments’ under the Wft. If a party executes or receives and passes on orders for such
financial instruments on a regular basis, it could be construed as an ‘investment firm’ that
performs ‘investment services’ as meant in the Wft, for which activity a licence from the
Dutch Financial Markets Authority is required unless one of the Wft exemptions applies.
iv Market developments
With respect to electricity, the Netherlands has moved from an electricity importing
country to an electricity exporter. There are plans to take a total of over 14GW of
new production into operation before 2018, an increase of approximately 50 per cent
compared to the current Dutch production capacity. In the development of the northwest
European electricity market, the attractiveness of the Netherlands as a location is
increasingly emerging as a prominent factor in producers’ investment plans. Plans for a
second nuclear power plant in the Netherlands have, however, been put on hold and are
unlikely to be revived anytime soon.
With respect to gas, the Dutch policy has been to build on the Netherlands’
gas position to become a gas hub (‘gas roundabout’) for north-west Europe, inter alia
by facilitating onshore gas storage and improving cross-border transport capacity. In
addition, in 2011 the first LNG terminal in the Netherlands (Gate) came into operation.
Most gas users in the Netherlands, including all households, use low calorific gas. This
can be gas from the Groningen field or converted high calorific gas from the small
fields. The declining production from the small fields means that increasing quantities
of foreign gas are needed for the supply of low calorific gas. This will mean that the
composition of low calorific gas will change. The Minister has reached an agreement
with GTS that allows the composition of low calorific gas to remain unchanged for at
least the next 10 years to that end-users do not have to replace installations. In addition,
there are approximately 60 large-scale users that are connected to a separate network of
GTS for high calorific gas. They do have to take measures to adapt to the changing gas
composition for high calorific gas.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Current government policy is based on collaboration and harmonisation of renewable
energy incentives at a European level. For the short term the Dutch government is
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committed to working towards achieving the European target of a 14 per cent share
of renewable energy by 2020. For the long term, the government’s approach is geared
towards the promotion of innovation in order to make renewable energy production
competitive. The government intends to achieve these aims by various means.
One is the so-called SDE+ scheme, whereby subsidies are granted to sustainable
energy projects. The SDE+ will be financed by a surcharge on the energy bills of consumers
and companies. The relevant legislation for the surcharge, which will be imposed as of
2013, is currently being drafted. The main options for achieving the renewable energy
target are onshore and offshore wind energy. Discussions are taking place regarding a more
coordinated planning approach to realise the ambition for 6,000MW onshore windpowered
generation capacity and various projects for offshore wind energy. Discussions
are also taking place on mandatory co-firing of biomass in coal-fired plants as well as on
obligation on suppliers to supply a minimum percentage of renewable energy. Finally,
a recent amendment provides for a possibility to deviate from the Acts for sustainable
local initiatives.
ii Energy efficiency and conservation
The 2006 European Energy Efficiency Directive has been implemented in the Netherlands
in the form of the Energy Efficiency Act as well as in the Acts. This implementation
covers a large number of aspects relating to energy efficiency, such as energy-saving
requirements for appliances and the rollout of smart energy meters. In addition, an
action plan for energy savings has been introduced to increase awareness for the potential
of energy savings in buildings.
The current government has also introduced the ‘Green Deal’ between the
government and society as a whole. The Green Deal aims to resolve any difficulties with
regard to energy saving and the generation of local sustainable energy and to show that
‘green’ and ‘growth’ can go hand in hand without large-scale subsidies.
When it comes to reducing carbon emissions there are two main projects. The first
is the European Energy Trading System in which the energy sector and major industrial
companies are the main participants. The emission rights are partly auctioned by the
government and partly allocated on the basis of European benchmarks. The second
project is carbon capture and storage (‘CCS’). A joint venture (Road) between E.On and
GDF SUEZ is currently developing a large-scale CCS demonstration project, whereby
CO 2
of a new coal-fired power plant is stored underneath the North Sea.
iii Technological developments
The Netherlands has specific strengths in the area of sustainable energy technology,
albeit that the solar sector has suffered recently. To further strengthen the innovative
capacity and competitiveness of the Dutch energy sector, energy has been designated
by the government as an economic ‘top sector’ that should benefit from a modern form
of industrial policy, including a joint innovation agenda for business, research institutes
and government and active energy diplomacy. The government has also set aside funds
for the promotion of trial projects for the development of smart grids. To enhance
infrastructure investments, a new procedure has been introduced in the Acts that offers
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network operators more certainty in advance on whether and how certain investments
can be recouped in the tariffs.
VI
THE YEAR IN REVIEW
The year 2011/2012 has been a transition year. The government that presided over the
Netherlands in this period has recently fallen and new elections are due in September.
The current caretaker government has emphasised that the transition to a cleaner supply
of energy must be beneficial to the Dutch economy.
The Minister has recently initiated a large-scale legislative review in order
to streamline and modernise the Acts. Part thereof will also be allowing for a partial
privatisation of TenneT and GTS. The ownership unbundling saga in the Dutch energy
sector, which has already demanded so much management time, is set to continue with
the recent request of the Dutch Supreme Court for a preliminary ruling to the Court
of Justice of the European Union on the compatibility of the group prohibition with
European law.
VII
CONCLUSIONS and OUTLOOK
Energy policy in the Netherlands has not always been very consistent, either in time
(in particular with respect to renewables) or in comparison with European policy (in
particular with respect to ownership unbundling). By 2025 it is expected that the
Netherlands will have become a net importer of gas. It remains to be seen to what
extent the next government is able to accelerate its ambitions with respect to making the
Netherlands a gas hub and achieving a low carbon-emission economy by 2050.
In the near future there will be wholesale revisions to the Acts, the entry into
force of the Heat Act, including secondary regulations, and – most likely – partial
privatisations of TenneT and GTS.
198

Chapter 17
Nigeria
Ken Etim and Ayodele Oni 1
I
OVERVIEW
The Nigerian oil and gas industry is made up of the upstream sector, comprising
exploration, drilling and production of oil and natural gas, a midstream sector comprising
transportation and refining of petroleum and gas, 2 as well as a downstream sector
comprising the importation, storage and distribution of petroleum products – an aspect
still highly regulated by the federal government of Nigeria. The Constitution 1999 of the
Federal Republic of Nigeria (‘the Constitution’) vests all petroleum in situ in the federal
government. As one of the largest producers of petroleum in the world, the Nigerian
petroleum industry is a major source of income for both the federal government and
the governments of the component states of Nigeria (‘the state governments’), with the
federal government involved in the industry as both participant and regulator.
The rights to the exploration and production of petroleum are granted by the federal
government through the issuance of oil exploration licences (‘OELs’), oil prospecting
licences (‘OPLs’) and oil mining leases (‘OMLs’). 3 The federal government also awards
rights to explore and extract petroleum through production-sharing contracts, which are
awarded in respect of OPLs and OMLs held by the state-owned oil company the Nigerian
National Petroleum Company (‘the NNPC’). The NNPC is also a major stakeholder in
several unincorporated joint ventures with international oil companies who act as operators
in respect of numerous OPLs and OMLs. Recently, government policy has focused on
increasing indigenous participation in all segments of the Nigerian oil and gas industry. The
1 Ken Etim is a partner and Ayodele Oni is a senior associate at Banwo & Ighodalo.
2 Liquefied natural gas (‘LNG’) is considered Nigeria’s key midstream product.
3 It is pertinent to note that, although, there is provision for the grant of OELs under the law,
OELs are no longer granted in practice as the current practice is the engagement of a seismic
data gathering service company to provide seismic information which is made available for
perusal by oil companies.
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Nigerian Oil and Gas Industry Content Development Act (‘the NCA’), enacted in 2010,
establishes a framework for ensuring increased Nigerian participation in the petroleum
industry. Of note is the fact that, the NCA provides for preferential treatment in the
award of licences and contracts to be accorded Nigerian incorporated companies in which
Nigerians hold at least 51 per cent of the equity shares. The NCA also makes it mandatory
for certain services to be sourced from Nigerian oil and gas industry service companies. 4
The Petroleum Act, Cap P10 Laws of the Federation 2004 (‘the PA’) is the
principal legislation regulating the oil and gas industry. The federal government is
currently proposing wide reforms in the oil and gas industry through the enactment of
the Petroleum Industry Bill (‘the PIB’). The PIB seeks to consolidate all major Nigerian
oil and gas laws, as well as introduce reforms to the rules, procedures and institutions
regulating the industry. Although introduced in 2008, the PIB is still being considered
by the National Assembly. Following the spate of nationwide strikes due to corruption
in the oil and gas industry 5 and the purported removal of the subsidy on the supply
of premium motor spirit (‘PMS’) by the government on 1 January 2012, the federal
government has established a committee to further review the PIB to address pertinent
issues in the industry. It is expected that this exercise will be concluded shortly and the
Bill represented to the National Assembly 6 for its consideration.
The Nigerian electricity industry is also divided into three broad segments:
generation, transmission and distribution. Until recently, the industry has been run
almost exclusively by the federal government, through the federal government-owned
vertically integrated monopoly (the National Electric Power Authority). Recognising
the poor state of the industry, however, and the need for reform in order to attract the
necessary investment to meet the electricity needs of the Nigerian economy, the federal
government is undertaking a major reform of the industry.
These reforms are based on the Nigerian Electric Power Policy 2001/2002 (‘the
NEPP’), and the Electric Power Sector Reform Act 2005 (‘the EPSRA’), which have
opened up the electric power industry to participation by the private sector. The EPSRA
provides for the licensing of private companies for the establishment of independent power
projects. Also, the government, through the Bureau of Public Enterprises (‘the BPE’) is
currently in the process of privatising, by open competitive bidding, the various generation 7
and distribution successor companies established to hold assets formerly owned by the
4 It is pertinent to note that the NCA does not preclude the 100 per cent foreign or non-Nigerian
ownership of companies in the oil and gas industry in Nigeria.
5 Corruption is allegedly more widespread than formerly believed in the downstream segment of
the Nigerian oil and gas industry.
6 The federal government operates a bicameral legislative system, whereby there are two Houses
that pass Bills into law, namely; the House of Representatives which is the lower house and the
Senate.
7 Private-sector participation in the two hydrogeneration companies (Kainji and Shiroro) is
expected to be through the granting of concessions as opposed to outright sale.
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Power Holding Company of Nigeria (‘the PHCN), 8 while retaining the electric power
transmission network for national security reasons. The government is, however, proposing
to award a management contract in this respect to ensure the effective running of, as well as
increased investment in, the Nigerian electric power transmission network.
II
REGULATION
i The regulators
The Federal Ministry of Petroleum Resources (‘the FMPR’) has overall regulatory oversight
of the Nigerian oil and gas industry. The FMPR acts primarily through the Department
of Petroleum Resources (‘the DPR’), the regulatory agency of the FMPR. The DPR is
responsible for the monitoring of the operation of petroleum companies and compliance
with petroleum laws and regulations, as well as the collection of rents and royalties.
Other regulatory bodies include the Petroleum Products Pricing Regulatory Agency (‘the
PPPRA’), which regulates the rates for the transportation and distribution of petroleum
products; the Federal Ministry of Environment, Housing and Urban Development,
which is responsible for approving environmental impact assessment reports in respect
of oil and gas projects; the Nigerian Content Development and Monitoring Board,
which is responsible for ensuring compliance with the NCA; and the Joint Development
Authority, which is responsible for the supervision of petroleum activities within the
Nigeria–São Tomé and Príncipe Joint Development Authority.
The principal Nigerian law is the Constitution, while the primary piece of legislation
regulating the exploration, production and distribution of petroleum and its derivative
products is the PA. The Constitution and the PA vest in the federal government, the entire
ownership and control of the petroleum resources in, under and upon any land in Nigeria.
Pursuant to the PA, the prospecting, exploration, production and distribution of petroleum
resources may only be undertaken with the consent of the Minister of Petroleum (‘the
Minister’) through the DPR’s issuance of leases, licences and permits for the prospecting,
exploration or distribution of petroleum and petroleum products.
The Petroleum (Drilling and Production) Regulations (‘the Petroleum Regulations’)
made pursuant to the PA regulates technical matters relating to petroleum production and
the licensee or lessee’s conduct of operations, including issues related to filing of monthly
progress reports of operations with the DPR, abandonment, assignments of participating
interests, permits to carry out seismic data surveys and fees, rents and royalty rates.
The Oil Pipelines Act regulates the construction, operation and maintenance of
gas pipelines and associated infrastructure. This legislation is also enforced by the DPR
and provides for the grant of licences and permits for the construction and operation of
oil or gas pipelines. It confers the right to construct, maintain and operate installations
that are ancillary to the construction, maintenance and operation of such pipelines. The
Petroleum Regulations, also administered by the DPR, regulate the transportation of
petroleum and natural gas derivatives in Nigeria.
8 The PHCN was the holding company (now unbundled) for the assets and employees of the
former state-owned vertically integrated company NEPA.
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The fiscal regime of the oil and gas industry primarily comprises the Petroleum
Profits Tax Act (‘the PPTA’) and the Companies Income Tax Act (‘the CITA’), which
regulate the taxation of profits made from the production and distribution of petroleum,
and the Deep Offshore and Inland Basin Production Sharing Contracts Act (‘the DIPSA’)
and the Petroleum Regulations, which prescribes the rates for royalties and rents. The
PPTA governs the taxation regime of upstream petroleum operations in Nigeria and
provides for an applicable tax of 85 per cent of the company’s chargeable profits.
The CITA governs the taxation regime of midstream and downstream petroleum
operations in Nigeria and provides an applicable tax of 30 per cent of the company’s
chargeable profits. The DIPSA provides fiscal incentives for companies operating in the
inland basin and deep offshore areas of Nigeria.
The National Environmental Standards and Regulations Enforcement Agency
Act, the Environmental Impact Assessment Act and the Environmental Guidelines and
Standards for the Petroleum Industry in Nigeria prescribe environmental and emission
standards applicable to petroleum activities in Nigeria.
There are a number of laws, statutory instruments and policies that may also
apply to companies engaged in natural gas operations, including the Companies and
Allied Matters Act, Nigerian Investment Promotion Commission Act, Pension Reforms
Act, the Immigration Act, the National Insurance Commission Policy Guidelines 2008,
the Foreign Exchange (Miscellaneous and Monitoring) Provisions Act, the Pre-Shipment
Inspection of Exports Act, the Customs and Excise Tariff, Etc (Consolidation) Act, the
Customs and Excise Management Act, the Personal Income Tax Act and the Harmful
Waste (Special Criminal Provision, Etc) Act.
In relation to the electric power industry, the primary regulator is the Nigerian
Electricity Regulatory Commission (‘the NERC’) mandated to regulate and issue licences
to participants in the industry. The main regulatory framework for the electric power
industry is provided by the EPSRA. By virtue of the EPSRA, the NERC is empowered
to issue licences in connection with activities such as electricity generation, transmission,
system operation, distribution or trading.
ii Regulated activities
As previously noted, the granting to investors of rights to develop natural gas reserves is
done via the issuance of permits and licences. In respect of licensing, there is generally
no distinction between oil and natural gas, and the relevant licences – OELs, OPLs and
OMLs – apply to both. The installation of oil terminals cannot be undertaken unless by
or under the authority of a licence or lease granted under the Minerals and Mining Act or
the express written approval of the Minister. Other governmental authorisations required
are a permit to survey a route for a proposed gas pipeline and an oil pipeline licence, both
issued under the Oil Pipelines Act.
The right to construct, maintain and operate a gas pipeline is granted via an oil
pipeline licence as well as rights to construct and operate ancillary installations, such as
pumping stations, storage tanks and loading terminals. A licence is also required for the
construction and operation of refineries This is the same licence required to construct
and operate gas-processing facilities.
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Nigerian law also requires the pre-shipment inspection of goods including
petroleum before export. Additionally, pursuant to the guidelines for the importation
of petroleum products into Nigeria (‘the Guidelines’), any company wishing to engage
in the business of importation of refined petroleum products is required to obtain an
import permit from the DPR. The Guidelines stipulate that all facilities for the storage
of imported petroleum products must be inspected by the DPR prior to grant of the
storage or sale licence. The DPR also issues licences for the transportation of petroleum
derivatives pursuant to the Petroleum Regulations, which prohibits the transportation
of many of such derivatives without an applicable licence. Where LNG is to be stored, a
licence to store LNG must also be obtained from the Minister.
Regarding the electric power industry, the EPSRA requires any person intending
to engage in the business of electricity generation, transmission, system operation,
distribution or trading to obtain the applicable licence from the NERC.
Applications for licences in relation to the aforementioned activities are to be
submitted to the NERC. The issuance of licences under the EPSRA is at the discretion of
the NERC. Applications are required to comply with the form prescribed in the relevant
regulations, and are required to be accompanied with the relevant application fees, as
well as non-refundable processing fees. Relevant application forms are provided by the
NREC. Within 30 days of NERC’s acknowledgment of the application, the applicant
is required to publish its intention to obtain a licence in one national newspaper and
a newspaper in the area it intends to operate and invite any objections thereto to be
submitted to the NERC for its consideration.
In granting a licence, the NERC is required to consider the interests of consumers
and the development of the industry generally. Other key criteria in granting licences
include that the applicant is suitably qualified to hold a licence, the applicant will comply
with all relevant laws and regulations as well as the terms and conditions of the licence,
and the grant of the application is in the public interest.
Where the application relates to transmission and distribution licences, the NERC
must be satisfied that the network has the relevant capacity to transmit or distribute
electricity in a safe market, and that open access is provided to all users with transparent
and non-discriminatory prices. It is also important to note that licences are not required
in respect of the generation of electric power not exceeding 1MW (in aggregate at a site)
or the distribution of not more than 100kW. Also, applicants that have acquired 10 per
cent or more of a company that holds a licence are required to disclose same to the NERC.
iii Ownership and market access restrictions
There are generally no restrictions in relation to the ownership of energy assets, service
providers or licence holders in the energy industry. The PA provides, however, that the
Minister may revoke an OML or OPL if the licensee or lessee company becomes controlled
directly or indirectly by a citizen of, or subject of, or a company incorporated in a country
whose laws do not permit Nigeria citizens or Nigerian companies to acquire, hold or
operate petroleum concessions on conditions which, in the opinion of the Minister, are
reasonably comparable with those applicable to Nigerian citizens or companies.
Pursuant to the EPSRA, licensees are precluded from acquiring or otherwise
affiliating with other licence companies without the prior approval of the NERC. It is
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also important to note that the NERC may issue licences upon such terms and conditions
as it may deem fit, which may include restrictions in relation to assignments or change of
control in the shareholding of the licence.
iv Transfers of control and assignments
The Securities and Exchange Commission (‘the SEC’), the regulatory body of the
Nigerian capital market, has regulatory oversight in respect of mergers and acquisitions.
Further to the Investment and Securities Act of 2007 (‘the ISA’), mergers and acquisitions
are generally subject to the prior review and approval of the SEC. The SEC has issued
guidelines and rules in respect of these to guard against anti-competitive practices and
they are applicable to all sectors, including the energy sector.
In considering whether a merger or acquisition is anti-competitive, the SEC will
consider whether same will result in any technological or other pro-competitive gain that
will be greater than, and offset, the effects of any prevention or lessening of competition,
which may result or is likely to result from the merger, and whether all shareholders
are fairly, equitably and similarly treated and given sufficient information regarding
the merger. After making this initial determination, the SEC may grant an approval in
principle to the merger. The timing for approval of such transaction varies based on the
complexity of the transaction. Where approval is given, an application is required to be
made to the Federal High Court to obtain approval for the merger.
Also, where a merger or change in control results in the direct or indirect
assignment of an OPL or OML, ministerial consent may be required. While these
licences may be transferred and even sometimes pledged as security, the enforcement of
such security, which could typically translate to an assignment of the OML, the OPL
or any right, power or interest arising therein, may only be done with the prior consent
of the Minister. An application for consent to an assignment shall be made in writing,
accompanied by the prescribed fee. There may also be a requirement for the payment of
other fees and or premium at the discretion of the Minister.
The consent requirement extends to the farm-out of marginal fields. Where
interests in OMLs or OPLs are transferred without the requisite consent, such a licence
or lease may be revoked. This is in addition to any pre-emption rights or rights of first
refusal that may exist by virtue of contract. There is, however, no restriction on booking
the rights for accounting purposes.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
A substantial part of the transportation pipelines, gas-processing facilities and other
associated infrastructure is currently owned and utilised by individual gas producers.
However, owners are required by law to provide access to available capacity, if any, upon
mutually agreed terms and under the supervision of the Minister.
In order to promote the utilisation of gas in the domestic and export markets, the
FMPR has developed a gas master plan and an infrastructure blueprint. The infrastructure
blueprint aims to optimise the development of gas facilities in line with government
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policy. It envisages the establishment of three central processing franchise areas, which
are to be concessioned to preferred bidders. These facilities will form the major hubs for
the processing of gas.
In the electric power industry, there are no vertically integrated players. The
federal government remains the dominant player in the industry, holding the majority of
the industry infrastructure. The government, through the BPE is currently in the process
of privatising the various generation and distribution successor companies established to
hold assets formerly owned by the PHCN.
Under the government’s privatisation plans, the various generation companies and
distribution companies will be sold to private companies under a competitive bidding
process. 9 The national transmission network, which is currently the only transmission
network in Nigeria will be retained by the federal government. It is expected that the
management of the Transmission Company of Nigeria, which holds the transmission
assets, will be contracted out to ensure the optimal running of the transmission network.
ii Transmission/transportation and distribution access
As regards, the electric power industry, regulations that require holders of transmission
and distribution licences to provide non‐discriminatory open access to other licensees
provided there is available capacity to do so, have been recently issued. Notwithstanding
third-party access rights, existing electricity distribution companies have exclusivity with
respect to their areas of coverage, which typically is about three to five component states
of Nigeria, except for two of the 11 distribution companies that cover only Lagos state.
Regarding oil and gas, the Oil Pipelines Act provides that any person who
requires access to any pipeline may make an application to the Minister, who considers
the application in consultation with the owner of the pipeline. The Minister will
grant the application if he is satisfied that the pipeline can conveniently convey the
substance the applicant wishes to convey. The terms and conditions of the access will
be as negotiated and agreed upon between the parties; where the parties fail to reach
an agreement, the Minister may impose such terms and conditions that he deems
expedient to secure the access rights of the applicant and to regulate the access charge.
Notwithstanding the foregoing, gas distribution companies typically have exclusive
rights to their franschise areas.
iii Rates
The NERC is mandated under the EPSRA to regulate prices in the industry with a view
to ensuring fair pricing for consumers of electricity as well as ensuring sufficient returns
for market participants. The EPSRA further empowers the NERC to establish one or
more tariff methodologies for regulating electricity prices. The NERC, in consultation
with market participants, established the Multi-Year Tariff Order (‘the MYTO’), a tariff
structure for all levels of the industry, which incorporates all cost elements in order
to arrive at electricity prices that are reasonable and guarantee a minimum return on
investment for market participants.
9 Two generation companies that are hydropowered would be under concession and not sold.
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The MYTO also provides incentives for participants who are able to achieve a
higher efficiency in their operations. The structure is such that at the commencement
of the MYTO all prices will be regulated; however, this will be reduced over time
as competition increases in the market and electricity supply is sufficient to meet
requirements of the market.
The PPPRA, on the other hand, regulates the rates for the pricing and distribution
of petroleum products. The pricing template is a pricing information sheet detailing
the components used in deriving the PPPRA daily or monthly guiding products prices,
which in turn affects the rates paid. Access charges to gas pipelines are negotiated and
determined by the parties but are subject to the approval of the Minister.
iv Security and technology restrictions
The National Office for Technology Acquisition and Promotion Act (‘the NOTAP Act’)
requires the registration of all contracts involving the transfer of technology between
Nigerian and foreign companies. The NOTAP Act sets maximum limits for charges that
may be imposed by foreign companies in connection with the provision of such technical,
training, management and other such technology acquisition or transfer agreements.
Failure to register such contracts with NOTAP will result in the Nigerian company not
being able to access official Forex markets and approved government channels for the
purpose of making payments under such contracts.
With respect to security of critical information on the energy sector and the role
of cyber security in this respect, concrete steps are being taken by the federal government,
to ensure same, through a number of cyber-security bills as well as critical infrastructure
protection being considered by the Nigerian legislative houses. 10 Further to the federal
government’s desire to, inter alia, protect such information, a committee was recently
set up by the executive arm of the federal government to review the Bills before the
legislative houses with a view to assisting in fine-tuning same before enactment into law.
IV
ENERGY MARKETS
i Development of energy markets
As previously noted, the electricity industry is currently undergoing significant changes
with the introduction of private industry participation. Currently, there are several licensed
active independent power projects (‘IPPs’) operating in the industry. Many of these IPPs
were established for the sole purpose of supplying electricity to particular areas, companies
or cluster of industries or industrial areas, while others supply electricity directly to the
national grid. As there is only one electric power transmission network in the country,
dedicated IPPs are typically located around the areas or companies that they supply.
The federal government established the Nigerian Electricity Bulk Trading Company
plc (‘the Bulk Trader’) to act as an interface between the electric power generation segment
and the electric power distribution segment of the electric power industry, because of
concerns as to the creditworthiness of companies in the power distribution segment
10 Nigeria’s federal legislative houses are the House of Representatives and the Senate.
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of the industry. 11 The Bulk Trader’s functions include negotiating and executing power
purchase agreements (‘PPAs’) with the privatised PHCN successor-generation companies,
assuming the responsibilities under existing PPAs entered into by the PHCN, as well as
negotiating PPAs with interested IPPs. It is understood that the World Bank will provide
partial risk guarantees in respect of the payment obligations of the Bulk Trader.
Natural gas trading is mainly controlled by the Nigerian Gas Company (‘the
NGC’), which, due to its ownership of the major transmission infrastructure, plays
the role of gas merchant in Nigeria and grants franchises to private companies for the
distribution of gas within established distribution zones.
ii Energy market rules and regulation
The government has issued National Gas Supply and Pricing Regulations, which set out
a pricing framework for gas supplied to different sectors of the domestic market. The
Pricing Regulations also impose a domestic supply obligations on natural gas producers,
the fulfilment of which is a prerequisite for an export gas project. Outside the domestic
supply obligations of gas producers, natural gas is sold on a willing-buyer, willing-seller
basis, and the pricing is negotiated on a bilateral basis.
The pricing of grid electric power supply is, however, regulated by the MYTO.
Where the electric supply is to be off-grid, parties may negotiate such terms and
conditions, including pricing that would regulate their relationship under the electric
power sale agreement.
There is at the moment, no exchange-traded energy derivatives market in Nigeria.
Any such derivative arrangement would typically be over the counter.
iii Contracts for sale of energy
Market participants are free to enter individual contracts for the sale of power or natural
gas. Where such natural gas sale is for sale of gas that falls within the purview of a
company’s domestic supply obligation, a standard template gas sale and aggregation
agreement, already being finalised by stakeholders, is required to be used with many
of the terms, such as pricing formulae, force majeure definition, and such other predetermined
terms. Only a few terms that are party-, plant- or location-specific are
typically negotiated on bilateral basis.
With respect to power, there are also the template bulk PPAs and vesting
contracts that are used for grid power sale and purchase pursuant to the ongoing reform
programme. Like the template gas agreement, many of its terms are fairly standard and
fixed with only a few terms considered as bilateral terms subject to negotiations.
It is expected that the regulatory bodies for both the petroleum industry and power
may mediate in negotiations. It is also the case that the prudence of utility purchases of
power or natural gas is subject to regulatory scrutiny.
11 Please note that this does not create a single-buyer model, such that a generation company is
still allowed to sell to a distribution company of its choice.
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iv
Market developments
Nigeria
The ongoing reform and power sector privatisation remain the primary developments in
the electric power sector. It is expected that the privatisation process will be concluded
during the course of 2012, with an industry review of proposed transaction documents
currently in progress. The current deadline for submission of financial and technical bids
is currently set at 31 July 2012, with the announcement of preferred bidders to take place
in October 2012.
Also, following the recent nationwide strikes in response to the purported removal
of the subsidy on PMS, the federal government has established a committee to review the
PIB with a view to re-presenting same to the National Assembly for consideration. The
PIB is expected to introduce wide reforms in the oil and gas industry. However, there is
no indication on when the bill will be passed into law.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
A national energy policy was approved by the federal government in 2003 with the
overall thrust of optimal utilisation of the nation’s energy resources; both conventional
and renewable, for sustainable development and with the active participation of the
private sector. There is also the Renewable Energy Master Plan (‘Renewable Energy
Plan’), which aims to upscale the use of renewable energy in Nigeria. The Renewable
Energy Plan articulates Nigeria’s vision for achieving sustainable development. The
plan also aims at moving the economy from a monolithic fossil economy to one driven
by an increasing share of renewable energy in the national energy mix. It involves
the exploitation of renewable energy in quantities and at prices that will promote the
achievement of equitable and sustainable growth.
In the year 2005, a Presidential Directive was issued to the NNPC to explore the
development of renewable energy in Nigeria. The NNPC, through its Renewable Energy
Division, has promoted the production and importation of biofuels such as biodiesel
and fuel-ethanol to be blended with PMS with a view to reducing carbon emissions.
The regulation of the production and importation of biofuels is carried out by the DPR.
ii Energy efficiency and conservation
Energy efficiency regulations are currently absent in Nigeria. The process of extraction,
conversion and utilisation of energy is prone to wastage. Apart from direct losses, the
inefficient use of energy has resulted in increased cost of energy products and services,
faster depletion of energy resources and environmental degradation. The concept
of sustainable development, therefore, dictates that deliberate efforts be made to
promote efficiency in the production, conversion and utilisation of energy. The Energy
Commission of Nigeria (‘the ECN’) has developed a draft national energy policy and the
draft Energy Master Plan that contains basic policies and strategies for energy efficiency
and conservation. Specifically, the policy provides for the promotion of energy efficiency
and conservation in industrial, residential and transport sectors. The master plan also
provides for the designing of a national programme on industrial energy efficiency and
conservation in collaboration with the Manufacturers’ Association of Nigeria and experts
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in higher institutions and research centres. The policy also aims at the introduction of
fuel-efficiency labelling programme in the transportation sector for various vehicle types.
The policy also provides for establishing codes and standards for energy efficiency
and conservation technologies. The Commission has also recently established an
Energy Conservation Research Centre. There is also a pilot compact fluorescent lamps
(‘CFLs’) programme being anchored by the ECN in collaboration with the Economic
Community of West African States (ECOWAS) and the Cuban government to replace
1 million incandescent lamps with CFLs. In the power sector, the NERC has initiated
some processes towards developing energy efficiency regulation. Specifically, the NERC
is currently developing energy efficiency labelling standards for domestic appliances,
energy efficiency standards for luminaries and other household appliances.
iii Technological developments
Smartgrid technologies are yet to be implemented in Nigeria.
VI
THE YEAR IN REVIEW
The Shell Petroleum Development Company, which currently holds a large number
oil and gas concessions in Nigeria is currently exiting some of its onshore oil and gas
concession areas as a result of the conflicts it has been having with host communities
in those areas. Its decision to exit those concessions has opened up the industry for
participation by several indigenous Nigerian companies and other independents. Shell is
currently concluding negotiations in respect of its assignment of its participating interest
in a number of its concession areas.
Additionally, as regards the power sector, the federal government is in the process of
finalising the sale of its majority stake in 17 power generation and distribution companies
and concluding the negotiation of a management contract for the transmission network.
In the downstream petroleum segment, there are plans by the federal government to
deregulate the sale and marketing of petroleum products, remove subsidies, encourage
companies to build more refineries and, consequently, refine more crude oil in Nigeria.
VII
CONCLUSIONS and OUTLOOK
Although Nigeria has its fair share of challenges in the energy sector, it appears that the
ongoing reforms in the entire energy supply chain, have come at an auspicious time and
if the federal government forges ahead with its reforms, the energy sector generally would
open up further for private sector participation, with improved energy security. For
success to be recorded, however, issues such as corruption, nepotism and inconsistency in
government policy must be adequately dealt with. Additionally, the federal government
must act transparently while showing that it has the political will to conclude the ongoing
reforms. The outlook therefore appears to be positive, largely because of the yawning gap
in energy demand and supply and the ongoing reforms. Nigeria may well be particularly
attractive to prospective investors if the ongoing reforms are successful.
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Chapter 18
Norway
Per Conradi Andersen and Christian Poulsson 1
I
OVERVIEW
The Norwegian onshore energy sector is almost entirely based on electricity generated by
hydropower. Other energy sources play a rather modest role in the onshore energy sector.
Hence, the description in this chapter will focus on electricity generated by hydropower.
The Norwegian electricity sector is highly influenced by public ownership
combined with tough restrictions on private ownership. This does not necessarily differ
from other countries around the world, but stands in contrast to the fact that Norway
has since 1990 had a well-functioning market for electricity and connected commodity
derivatives ahead of most other countries.
Main sources of law are the Industrial Concession Act, the Watercourse Regulation
Act, the Energy Act, the Water Resources Act and the Ocean Energy Act.
II
REGULATION
i The regulators
The Ministry of Petroleum and Energy (the OED) holds the overall administrative
responsibility for energy and water resource management in Norway. The Ministry is
responsible for ensuring that the resource management is carried out in accordance with
guidelines given by Parliament.
The Norwegian Water Resources and Energy Directorate (‘the NVE’) is a
subordinate agency of the Ministry. The NVE holds the managing responsibility
according to the Energy Act and the Water Resources Act. Furthermore, the NVE assists
the Ministry of Petroleum and Energy in managing the Industrial Concession Act and
the Watercourse Regulation Act. The NVE has legislative powers to issue regulations and
1 Per Conradi Andersen and Christian Poulsson are partners at Kvale Advokatfirma DA.
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individual decisions and perform preparatory procedures of cases to be resolved by the
Ministry of Petroleum and Energy.
Statnett SF is the National Grid company and transmission system operator
(‘TSO’) responsible for operation and development of the central grid for electricity
transmission.
ii Regulated activities
A concession is mandatory for anyone who wants to develop hydropower plants,
windpower plants, gas-fired power plants, power lines, district heating systems and
domestic transmission pipelines for natural gas, etc.
The Industrial Concession Act specifies that anyone who acquires ownership, user
rights or long-time user rights to a waterfall, or shares in companies with such rights,
must obtain a licence. Development of a waterfalls and construction of a power plants
usually require an additional licence pursuant to the Water Resources Act.
The Energy Act requires licensing for the construction, ownership and operation
of all installations for generation, conversion, transmission and distribution of electricity,
all the way from power plant to consumer, as well as for district heating plants over
10MW. A licence pursuant to the Energy Act is also required for trade in electricity and
for the organisation of marketplaces for such trading.
Systems for transporting natural gas intended for delivery to natural gas
undertakings in another region, cannot be constructed or operated without a licence
pursuant to the Natural Gas Act. Minor liquefied natural gas installations and small-scale
facilities for transmission or distribution of natural gas do not need to be licensed.
A developer or licensee must have a licence pursuant to the Watercourse Regulation
Act to carry out regulatory measures or divert water in a watercourse.
The Watercourse Regulation Act gives the licensee the authority to expropriate
the necessary property and rights in order to carry out the regulatory measures. For other
energy projects, corresponding expropriation rights are laid down in the Expropriation
Act of 1959. Expropriation questions are often handled as part of the licensing process
for energy projects.
The Ocean Energy Act regulates renewable energy production, conversion and
transmission of electricity at sea. A licence is needed on order to construct, own or
operate production facilities and cabling systems located outside the baseline, but within
the Norwegian continental shelf. The same applies to reconstruction or extension of such
existing facilities.
iii Ownership and market access restrictions
Norway has for more than 100 years had huge restrictions on acquisition of waterfalls
and hydropower generators. During the 20th century these were developed to include
restrictions on the lease of such facilities and partial ownership in a way that established
preferential treatment of public (state, counties or municipalities) ownership.
The main principle on acquisition of ownership to hydropower plants is found
in the Industrial Concession Act (of 14 December 1917). Without a concession, only
the Norwegian state may acquire ownership or the right to use waterfalls of a certain
size. The threshold for when concession has to be applied for has recently been raised
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from 1,000 (736kW) to 4,000 natural horsepower. Waterfalls under this limit may be
acquired or rented without concession.
Norwegian state enterprises, municipalities and counties will normally be
entitled to a concession for the acquisition of a waterfall. The same applies to joint-stock
companies, partnerships and other companies in which at least two-thirds of the capital
and the shares are owned by a Norwegian state enterprise, a Norwegian municipality or
county (i.e., a publicly owned company).
Private entities (domestic and foreign) as well as publicly owned foreign companies
may, on application, be granted a concession to acquire ownership to one-third of the
waterfall or the company registered as a owner of the waterfall.
Prior to 2008–2009 concessions for the acquisition or rent of waterfalls or other
acquisitions of production rights were given to private owners or foreign public owner
for a maximum of 60 years. In contrast, Norwegian public owners or publicly owned
companies may be (and have always been) given concessions in perpetuity.
When a concession was granted for a maximum of 60 years, several conditions
would apply. The most important concerned reversion of the shares or the waterfall
rights (including power plants, etc), which would be assigned to the Norwegian state
without compensation at the end of the concession period. There are still concessions
with such conditions in place, so several power plants will likely revert to state ownership
in the future. To avoid reversion a private owner may transfer ownership (through a
regular sale) to publicly owned companies before the date for reversion. This will most
likely lead to transactions regarding hydropower plants in the future.
The reversion scheme was challenged by the EFTA Surveillance Authority (ESA)
under the EEA agreement in 2006. After a ruling in the EFTA Court the Norwegian
government had to change the legislation. The system of reversion was abolished for new
acquisitions, and the private entities and publicly owned foreign entities were no longer
able to acquire waterfalls. Such entities are now only able to acquire one-third of publicly
owned waterfalls or companies holding such assets.
As an equivalent to transfer of ownership it is still possible to lease waterfall rights
with adjacent generators, but only for a maximum of 15 years. The lessee has to apply for
a concession when parties enter into such agreements.
According to the Energy Act a licence is necessary to own and to operate electricity
grids (transmission and distribution) and certain installations such as transformers.
iv Transfers of control and assignments
Transfer of more than 20 per cent ownership to companies holding licences, according
to the Industrial Concession Act, will need an acceptance from the government (OED).
If as much as 90 per cent is acquired this will be considered as an acquisition of the
underlying assets and will need a complete concession process. Generally, the Act is
construed as catching up with agreements where a party receives a position equivalent to
direct ownership through voting rights, shareholders agreements, etc.
In contrast with the Industrial Concession Act the Energy Act has no regulation
on partial transfer of ownership to companies holding such assets or licences; however,
acquisition of more than 90 per cent will be considered as a change of ownership to the
underlying assets, even if the business continues unchanged.
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III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i
Vertical integration and unbundling
The Norwegian Energy Act is based on the principle that natural monopolies, such as
operation of the grid, shall be protected from any influence from, and cross-subsidies
to, the competitive market embracing generation and trade of electricity. Since the Act
was implemented in the early 1990s the authorities have been given incentives in order
to fulfil the aim of splitting up vertically integrated companies into separate entities,
preferably as limited liability companies covered by the Limited Liability Company Act.
ii Transmission/transportation and distribution access
Grid companies with area licences have a supply requirement, according to Section 3-3 of
the Energy Act. The supply requirement entails a connection requirement towards nonprofessional
(private) customers. For producers, the grid company’s only requirement will
be to provide market access with non-discriminatory and objective tariffs and conditions.
Grid companies can require an investment contribution to cover construction
costs of connecting new production or extending production capacity.
In cases where the connection causes reinforcement of installations with several
network users, a pro rata share of these costs may be included in the investment
contribution.
iii Rates
The Norwegian Water Resources and Energy Directorate (‘the NVE’) is responsible for
monitoring grid management and operations, including the determination of income
caps for each grid company. The income cap reflects factors that influence area-specific
costs, such as climate, topography and settlement patterns. The company’s income, which
mainly derives from transmission tariffs, must not exceed the maximum permitted level
determined by the NVE. This system is intended to ensure that grid companies do not
make unreasonable monopoly profits and that cost reductions also benefit grid customers.
Income caps are updated annually. To promote quality of service, a mechanism
that imposes direct consumer compensation for long interruptions was introduced in
addition to the already existing mechanisms that provide for a reduction in the total
revenue for the grid companies when interruptions occur.
All grid companies are required to use point tariffs when charging for transmission
and distribution. Point tariffs mean that grid customers pay the same transmission tariff
regardless of whom they buy electricity from or sell to. An individual customer only
pays a transmission tariff to its local grid company. Consumers pay one tariff to tap
electricity from one point in the grid (consumption tariff) whereas generating companies
pay another tariff to feed power into a connection point (input tariff).
The grid companies’ transmission tariffs are regulated by Regulation No. 302
of 11 March 1999 concerning financial and technical reporting, permitted income
for network operations and transmission tariffs. The regulations require that tariffs to
household customers must consist of a fixed component and an energy component.
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The fixed component is a fixed annual amount and shall, at minimum, cover
customer-specific costs. These are costs related to metering, settlement, invoicing,
etc. This component is independent of the current input of power and will give grid
companies sufficient income according to regulated permitted income fixed annually for
each company by the NVE. The central grid input tariff will be normative for the fixed
component by power input into regional and distribution networks.
The energy component depends on the customer’s current input of power. When
power is transmitted some of the power is lost. The energy component reflects costs
(kroner per kWh) related to power loss when one extra kWh is transmitted (marginal
loss). The energy component refers to the connection point.
In addition, the transmission tariff (i.e., fixed component plus energy component)
covers the fixed costs in the network.
iv Security and technology restrictions
As a result of increased fear of terrorism around the world and climate change, the
authorities have increased focus on security of supply in the energy sector.
On 22 July 2011 Norway was struck by a major act of terror where a huge explosion
damaged the buildings housing the government, among them the Ministry of Petroleum
and Energy. Later, during last winter several parts of Norway were struck by storms that
took down the electricity grid in many places. More than 421,000 people were without
electricity for some time during the Christmas period as a result of storm Dagmar. This
lasted for several days for more than 10,000 people. This has led to an increased focus on
transmission tariffs and the grid companies’ duty to maintain the quality of the grid.
IV
ENERGY MARKETS
i Development of energy markets
The Nordic countries’ power systems are interconnected, and the countries’ systems are
mutually dependant. The power price is determined in the market based on generation,
transmission and consumption conditions in the Nordic region, and thus both short and
long-term prices will vary. The power price also reflects possible congestion in transmission
capacity between the areas, but the price will be the same in all areas of the Nordic region
if there are no such congestion. Water inflow to hydropower plants is of great importance
for the determination of the power price, since hydropower represents such a large share
of the Norwegian and Nordic power supply. In Norway, consumption is slightly higher
than the power production in years with normal precipitation and temperature conditions,
which means that Norway is dependent on imports from abroad. In years with low inflow,
the need for power imports is even higher. Temperature and weather conditions influence
short-term demand in the Nordic region and Europe, which also affects the power prices.
Periods of cold temperatures and high demand can especially result in higher power prices.
Wholesale market
The power market is often divided into wholesale and end-user markets (retail market).
The wholesale market embraces generators, suppliers, large industrial enterprises, traders
and other undertakings. Electricity is traded physically on a day-ahead basis in the spot
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market organised by the Nordic power exchange, Nord Pool Spot, which accounted
for a traded volume of approximately 316TWh in 2011. In addition, wholesale players
trade power derivatives representing multiple volumes in the financial forward or futures
market organised by Nasdaq OMX Commodities. Electricity is also traded bilaterally
between wholesale players, both on a physical and financial basis.
End-user market
Anyone who buys electricity for his or her own consumption is an end-user. Small endusers
normally buy power from an electricity supply company. Larger end-users, such as
industrial enterprises, often buy directly in the wholesale market.
All end-users are free to choose electricity supplier and contract type. The most
common contracts for households have prices that vary according to market conditions.
International power trading
Norway was traditionally a net exporter of power; however, in the late 1990s consumption
of electricity rose faster than the power supply, as hydropower development has been
limited in recent times. Thus, Norway is on average a net importer.
Norway has interconnectors towards Sweden, Denmark, Finland, the Netherlands
and Russia. The transmission capacities towards Finland and Ruåssia are low, and the
connection with Russia is used only for imports to Norway. The highest transmission
capacity from Norway goes to Sweden, at about 3,600MW, while the capacity in the other
direction is somewhat lower. Capacity between Norway and Denmark is about 1,000MW.
ii Energy market rules and regulation
Nord Pool Spot organises the leading power market in Europe and offers both day-ahead
and intraday markets to its customers. 350 companies from 20 countries trade on the
market. In 2011 the group had a total turnover of 316TWh, which includes the auction
volume in the UK market N2EX. In 2010, total volumes traded over Nord Pool Spot
amounted to 310TWh, including the UK auction volume on N2EX. This represented
a value of €18 billion.
Nord Pool Spot AS is owned by the Nordic transmission system operators
Statnett SF (30 per cent), Svenska Kraftnät (30 per cent), Fingrid Oyj (20 per cent)
and Energinet (20 per cent). Nord Pool Spot AS is licensed by the NVE to organise and
operate a market place for trading power with physical delivery, and by the Norwegian
Ministry of Petroleum and Energy to facilitate the power market with foreign countries.
Nord Pool Spot and NASDAQ OMX Commodities operate the N2EX in the
UK market.
While a licence is required under the Energy Act in order to trade or organise
marketplaces for physically deliverable electricity (see Section II.ii, supra), certain aspects of
regulation of financial trading in electricity falls under the Securities Trading Act. Regulated
activities include receipt, mediation and execution of orders, portfolio management and
investment advice in electricity derivatives, all of which require an investment services
licence. The licensing regime implements Directive 2004/39/EC (‘the MiFID’). In
addition, the Securities Trading Act regulates market behaviour such as insider dealing and
market manipulation by implementing the requirements of Directive 2003/6/EC (MAD).
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iii
Contracts for sale of energy
Norway
Physical or financial electricity trading that take place on Nord Pool Spot, Nasdaq
OMX Commodities or other regulated marketplaces follow standardised contracts and
rulebooks applied by the relevant exchange or regulated marketplace in respect of the
product in question.
Bilateral over-the-counter contracts for sale of electricity in the wholesale
market are also to a large extent standardised. Different organisations have contributed
with standardised contracts, including Nordic Association of Electricity Traders
(NAET), European Federation of Energy Traders (EFET) and International Swaps and
Derivatives Association (ISDA). These types of trade usually take place within a master
agreement framework that provides for swift exchange of documentation in respect
of individual trades, as well as risk-mitigating mechanisms such as early termination
and netting in the event of bankruptcy. Such mechanisms are generally recognised by
Norwegian law insofar as commodity derivatives are concerned. The demarcation of
commodity derivatives under Norwegian law follows basically the demarcation applied
under the MiFID. This means that, as a rule, financially settled electricity contracts
may generally be netted in a bankruptcy situation, while the same only holds for
certain physical contracts.
Contracts for sale of electricity to households and similar end-users are generally
standardised by the retail electricity suppliers, while larger contracts concerning electricity
deliveries to industrial end users vary significantly depending on the commercial strength
of and negotiation process between the parties.
iv Market developments
The Norwegian electricity market has since its deregulation, represented by the Energy
Act in 1990, developed to become one of the most liberal electricity markets in the
world, easily accessible to producers, end-users and traders alike.
On the power production side, due to the Norwegian–Swedish electricity certificate
scheme introduced from 1 January 2012, there is a marked expectation for the installation
of significantly more production capacity in the years to come (see Section V.i, infra).
Coupled with expected lower electricity consumption in the industrial sector, as well as
limited transmission capacity between the Nordic market and continental Europe, there is
a growing concern in the market that electricity prices will drop in the long term.
On the regulatory side Norwegian law is closely connected to EU law through the
EEA Agreement. Thus the developments in this sector are on an overall basis expected to
track developments in the EU.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Since 1 January 2012, Norway has been part of a Norwegian–Swedish electricity
certificate market, which was introduced to increase production of renewable energy.
Until 2020, Norway and Sweden intend to expand their electricity production
based on renewable energy sources by 26.4TWh. This corresponds to the power
consumption of more than half of all Norwegian households.
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a
b
c
The following plants are entitled to electricity certificates:
power plants based on renewable energy sources (hydro or wind) where
construction started after 7 September 2009;
existing power plants expanding their production on a permanent basis,
construction started after 7 September 2009; and
hydroelectric power stations with installed capacity up to 1MW where
construction started after 1 January 2004.
The system may cover the entire production or parts of it.
Power plants must be built in accordance with the licensing terms or comply
with conditions for exemption from licensing. Any government investment aid received
needed to be repaid before 30 April 2012 in order to receive certificates.
All actors delivering electricity to end-users must buy or obtain by other means
(e.g., own production) a certain yearly quota of electricity certificates. In addition,
certain electricity users that have entered into bilateral agreements (e.g., with a producer)
have to buy electricity certificates. Moreover, generators who use their own electricity are
to a certain extent required to buy electricity certificates.
The end-users finance the system, as the costs of purchasing certificates is added
on the electricity bill; however, the certificate cost must be an upfront fixed part of the
suppliers’ handling costs. In this way the suppliers must calculate the cost before delivery
starts and in this respect compete with other suppliers in offering the lowest handling
costs. Still, the certificate costs are shown as a separate item on the invoice to customers.
The NVE manages the electricity certificates in Norway in cooperation with
Statnett (register coordinator) and Energimyndigheten (the Energy Agency) in Sweden
in order to develop a well-functioning Norwegian–Swedish electricity certificates market.
Statnett issues electricity certificates to accredited power generators and maintains
an electronic certificate register that shows how many electricity certificates power
producers and electricity certificate-liable actors hold.
Certificates are sold on the Norwegian–Swedish electricity certificate market.
Power suppliers and some electricity users are required to purchase electricity certificates
for a certain proportion of the electricity they deliver or use.
The NVE and the Energy Agency accredit power plants that receive one electricity
certificate for each MWh of electricity generated. Thus, the support is independent of
whether the power plant is located in Sweden or Norway, and which renewable energy
source is used.
Participants liable for electricity certificates (i.e., the power suppliers and certain
electricity users) may choose to purchase their electricity certificates in Norway or Sweden.
Trading of electricity certificates across national borders means that the renewable energy
resources in both countries are utilised more effectively than if national markets were
established.
The price of electricity certificates is determined by supply and demand. The
demand is determined by how much power is used and the set electricity certificate
quota for each year. The supply is dependent on how much electricity is being produced.
Large-scale investments in new energy production will result in many certificates in the
market and the price of each certificate will drop. Few power plants under construction
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will cause rising certificate prices until prices reach a level where the energy market will
attract new investors.
ii Energy efficiency and conservation
Both the NVE and ENOVA focus on energy efficiency. While the NVE implements
regulations regarding energy efficiency, ENOVA is a state-run entity supporting various
activities and incentives in order to trigger a transfer to environmental means of energy
generation in Norway.
ENOVA’s programmes and activities within industry, construction and housing
are meant to stimulate the market into introducing new energy-efficient solutions and
adopting them in practice. In recent years, construction programmes have been revised
and now have a greater focus on innovators in the market, in particular the passive house
standard. In addition, ENOVA focuses on increased use of alternative sources, increased
production from renewable energy sources and the introduction and development of
new technologies and solutions.
iii Technological developments
Norway is at the forefront of development of offshore floating wind power generation.
Statoil’s Hywind project is the first full-scale floating wind turbine in the world.
In 2009, Statoil invested about 400 million kroner in construction and completion of
the pilot, including scientific research and development of the wind turbine concept.
ENOVA SF has given 59 million kroner in support of the project.
The concept has been verified during the first two years of testing and the results
have been above expectations. With few operational challenges, great production results
and well-functioning technical systems, it is expected that the Hywind concept will have
great influence on offshore wind production in the future. Statoil is at present looking
for possible future locations within the United States and the United Kingdom for pilot
wind farm projects with three to five floating wind turbines.
VI
THE YEAR IN REVIEW and OUTLOOK
The past year has offered a few notable changes. This is first related to the introduction
of the electricity certificates with a common market between Norway and Sweden. It
remains to be seen whether the certificates will boost new projects up to the ambitious
level of 26.4TWh by 2020. It is, however, certain that the market players as a result of
this new scheme will be focusing on a new commodity that will have to be traded up to
a defined minimum. The coming year will show to what extent there will be expanded
trade in these certificates.
The past year has also been challenging for the electricity grid, which suffered
great damage as a result of some extreme weather. This will doubtless have an influence
on the grid companies’ tariffs and future positions in relation to renewals, etc.
Finally, during the past year Norway also experienced some unusual changes in
temperature, rain or snow and drought, which has made the market prices on electricity
more volatile than before. It remains to be seen whether this will reflects normal future
variations due to climate changes or if the past year was merely exceptional.
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Chapter 19
Russia
Evgeny Danilov 1
I
OVERVIEW
Russia possesses enormous energy resources, the main being electricity generated by
thermal, hydro and nuclear power plants, gas, oil and coal.
The key programme document currently being implemented in Russia in the
energy sphere is the Energy Strategy for Russia up to 2030. 2 It states the aim of Russia’s
energy policy to be maximum effective use of natural energy resources and the potential
of the energy sector to assist stable economic growth, a better quality of life in the country
and consolidation of its foreign trade positions.
The fuel and energy complex holds a leading position in the Russian economy,
but the task of reducing the economy’s dependence on the energy sector is being
undertaken. The main current developments in the Russian energy sector are innovation,
modernisation and energy efficiency, a change in the structure and scale of production
of energy resources, reduced impact on the environment and climate, creation of a
competitive market environment, differentiation of export directions (with a reduction
in the share of the European countries), elimination of transit risks, further integration
into the global energy system and international energy security.
The electric power industry has been reformed, the electric power market is
being liberalised and the nuclear power industry reformed, more favourable conditions
have been created in the oil and gas complex, the development of oil refineries and
petrochemical plants is being encouraged, exchange trade in energy resources is
developing, and excessive administrative barriers in the activities of energy companies
are being lifted.
1 Evgeny Danilov is a head of group at Goltsblat BLP (the Russian Practice of Berwin Leighton
Paisner).
2 Energy Strategy for Russia up to 2030, approved by resolution of the government of the
Russian Federation, dated 13 November 2009, No. 1715-r.
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The energy sector retains a marked influence on the social situation in the country,
both as a sphere of employment and as a major factor in ensuring a comfortable lifestyle
for people living in a cold climate.
In 2010–2011, the following were also adopted and are now being implemented:
a a general plan for location of electric power facilities up to 2020–2030;
b a general plan for development of the gas industry up to 2030;
c a general plan for development of the oil industry up to 2020;
d a long-term programme for development of the coal industry up to 2030; and
e a state programme for energy efficiency and energy saving up to 2020.
II
REGULATION
i The regulators
According to the Russian Constitution, the generally recognised principles and rules of
international law and international treaties signed by Russia constitute an integral part
of the country’s legal system. If an international treaty sets out rules differing from those
established by Russian domestic law, the rules of the international treaty are applied, 3
including within the energy sector.
Russia is party to a whole series of international energy agreements with European
and Asian states, including members of the Commonwealth of Independent States.
Close contractual cooperation is implemented in the energy sphere within the scope of
the Customs Union of Russia, Belarus and Kazakhstan. 4
The President of Russia has published a document under the title ‘Russia’s
conceptual approach to the new legal basis for international cooperation in the energy
sphere (goals and principles)’. 5 On this basis, Russia proposes to conclude the following:
a an agreement on transit guarantees for energy materials and products, including
provisions on the procedure for overcoming emergencies in any given area (April
2009);
3 Part 4, Article 15 of the Constitution of the Russian Federation.
4 See: the Agreement on provision for parallel operation of the power grids of the participant
states in the Commonwealth of Independent States dated 25 November 1998; the Agreement
on electric power and capacity transit of the participant states in the Commonwealth of
Independent States dated 25 January 2000; the Agreement on mutual assistance in the event
of accidents and other emergencies at electric power facilities of the participant states in the
Commonwealth of Independent States dated 30 May 2002; the Agreement on formation of
an electric power market of the participant states in the Commonwealth of Independent States
dated 25 May 2007; the Agreement on provision of access to natural monopoly services in
the electric power sphere, including the fundamentals of pricing and tariff policy, dated 19
November 2010; the Agreement on unified principles and rules for regulating the activities of
natural monopoly entities dated 9 December 2010; and the Agreement on unified competition
principles and rules dated 9 December 2010.
5 Official site of the President of Russia, 21 April 2009.
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b
c
an agreement between Russia and the European Union on cooperation in the
implementation of infrastructure projects for the export of natural gas from
Russia to the EU and joint work on electric power grids (March 2012); and
an agreement between Russia and the European Union on the parallel operation
of the unified power grid of Russia and the power grids of Latvia, Lithuania and
Estonia (March 2012).
According to its Constitution, Russia is a federated state, in which state-controlled
facilities are run either by Russia (the federation), jointly by Russia and its constituent
entities (regions), or by the constituent entities of Russia independently. 6
Federal laws and other federal legal acts are adopted with respect to facilities run
by the state or jointly. 7
The country’s constituent entities exercise their own legal regulation, whereby
their laws and other legal acts do not run counter to federal ones.
The Constitution makes Russia responsible for establishment of federal policy
and federal programmes for economic development, the legal foundations of the unified
market, and the fundamentals of pricing policy, federal power grids, nuclear power and
security. 8 The main sources of national legal regulation of the energy sphere are the following
federal laws: 9
a Federal Law dated 26 March 2003 No. 35-FZ on Electric Power;
Federal Law dated 26 March 2003 No. 36-FZ on the Specifics of the Functioning
of the Electric Power Sector during the Transitional Period;
b Federal Law dated 21 November 1995 No. 170-FZ on Use of Nuclear Power;
c Federal Law dated 1 December 2007 No. 317-FZ on the State Corporation for
Nuclear Power ‘Rosatom’;
d Federal Law dated 31 March 1999 No. 69-FZ on Gas Supply in the Russian
Federation;
e Federal Law dated 18 July 2006 No. 35-FZ on Gas Exports;
f Federal Law dated 20 June 1996 No. 81-FZ on State Regulation in the Sphere of
Coal Mining and Use;
g Federal Law dated 27 July 2010 No. 190-FZ on Heat Supply;
h Federal Law dated 17 August 1995 No. 147-FZ on Natural Monopolies;
i Federal Law dated 29 April 2008 No. 57-FZ on Foreign Investment in Companies
of Strategic Importance for National Defence and Security;
j Federal Law dated 23 November 2009 No. 261-FZ on Energy Saving and Raising
Energy Efficiency;
6 Articles 1 and 5 of the Constitution of the Russian Federation.
7 Part 1, Article 76 of the Constitution of the Russian Federation.
8 Article 71 of the Constitution of the Russian Federation.
9 Hereafter, the mentioned federal laws and other legal acts are used in their latest versions,
including all subsequent amendments (as of 1 May 2012).
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k
l
Federal Law dated 21 July 2011 No. 256-FZ on Security of Fuel and Energy
Complex Facilities; and
Federal Law dated 3 December 2011 No. 382-FZ on the State Information
System of the Fuel and Energy Complex.
In accordance with the Constitution and the given federal laws, the state terms of reference
with respect to regulation of the energy sector are currently distributed as follows.
The Russian government regulates economic processes, develops and pursues state
structural and investment policies and implements energy development programmes. 10
It also heads up the unified system of state executive power in Russia, manages the work
of federal ministries and other bodies, distributes state functions between them and
exercises control over their activities, 11 including in the energy sphere.
The Energy Ministry implements state policy and legal regulation in the following
areas: 12
a the fuel and energy complex (electric power, the oil extraction, oil-refining, gas,
coal, shale and peat industries, major oil, gas and petroleum product pipelines,
hydro-carbon deposit development on the basis of production sharing agreements,
renewable energy sources);
b the petrochemical industry;
c heat supply (production and transmission of thermal energy involving combined
generation of electric and thermal energy);
d
e
energy saving and greater energy efficiency; and
formation and use of the state information resources of the fuel and energy
complex of Russia.
The Ministry for Industry and Trade implements state policy and legal regulation in the
sphere of energy saving and raising energy efficiency in goods circulation and in the area
of technical regulation. 13
The Federal Tariff Service implements legal regulation in the sphere of state price
(tariff) setting for goods (services) of natural monopolies and certain other entities and
exercises control over their implementation. 14 The natural monopoly entities in the
10 Article 14 of Federal Constitutional Law, dated 17 December 1997, No. 2-FKZ on the
Government of the Russian Federation.
11 Articles 1, 12, and 13 of the Federal Constitutional Law on the Government of the Russian
Federation.
12 Clause 1 of the Regulations on the Energy Ministry of the Russian Federation, approved by
resolution of the Government of the Russian Federation dated 28 May 2008 No. 400.
13 Clause 1 of the Regulations on the Ministry for Industry and Trade of the Russian Federation,
approved by resolution of the Government of the Russian Federation, dated 5 June 2008, No.
438.
14 Clause 1 of the Regulations on the Federal Tariff Service, approved by resolution of the
Government of the Russian Federation, dated 30 June 2004, No. 332.
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energy sphere are commercial organisations and other persons operating in the following
areas: 15
a electric power transmission services;
b services for operational dispatch management in the electric power sector;
c transportation of gas by pipeline;
d transportation of oil and petroleum products by major pipeline; and
e thermal energy transmission services.
The Federal Anti-monopoly Service exercises control over the following in the energy
sphere: 16
a observance of the anti-monopoly legislation, including the activities of natural
monopoly entities;
b foreign investment in natural monopoly strategic defence and security entities; 17
and
c orders for goods, work and services for state purposes.
The Federal Customs Service implements state policy and legal regulation and control
in the customs area. 18 It has a special subdivision, the Central Energy Customs, which
performs customs operations at its customs posts relating to energy resources (electric
power, gas, oil, coal, peat, coke, fuel shale) and their refined products. 19
The Federal Service for Environmental, Technological and Nuclear Supervision
implements state policy and legal regulation in the given sphere and is the federal state
energy supervisory authority, the federal state supervisory authority for nuclear power
use, and the federal state supervisory authority for industrial safety, including security of
electric power and thermal units and grids. 20
15 Clause 1, article 4 of the Federal Law on Natural Monopolies.
16 Clause 1 of the Regulations on the Federal Anti-monopoly Service, approved by resolution of
the Government of the Russian Federation, dated 30 June 2004, No. 331.
17 Other than natural monopoly entities in the sphere of electric power transmission via
distribution grids and transmission of thermal energy.
18 Clause 1 of the Regulations on the Federal Customs Service, approved by resolution of the
Government of the Russian Federation, dated 26 July 2006, No. 459.
19 Clause 1 of order of the Federal Customs Service, dated 20 February 2012, No. 299 on the
terms of reference of customs authorities in performance of customs operations relating to
energy resources; Regulations on the Central Energy Customs, approved by order of the Federal
Customs Service, dated 1 June 2007, No. 683.
20 Clause 1 of the Regulations on the Federal Service for Environmental, Technological and
Nuclear Supervision, approved by resolution of the Government of the Russian Federation,
dated 30 July 2004, No. 401.
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ii
Regulated activities
Russia
As a branch of the Russian economy, the electric power sector includes: 21
a production of electric power;
b transmission of electric power;
c operational dispatch management in the electric power sector;
d sale of electric power; and
e consumption of electric power.
Russia’s electric power complex consists of about 600 electric power plants, as follows:
a thermal power plants – 68.4 per cent (70 per cent working on gas, 26 per cent on
coal, and 3 per cent on fuel oil 22 );
b hydropower plants – 20.3 per cent; and
c nuclear power plants – 11.1 per cent. 23
The electric power wholesale market companies include eight open joint-stock companies
organised on a non-territorial basis (of these, six combine virtually all the major thermal
power plants, one, almost all hydro-power plants and one all the nuclear power plants),
and 14 open joint-stock companies set up on a territorial basis with electric power plants
on a smaller scale. Generation of electric power does not generally require a licence or
any other such state permit, except for nuclear power, which requires a permit (licence). 24
Electric power transmission services are provided by the organisation for
management of the unified Russian electricity grid (Open Joint-stock Company Unified
Power Grid, in which Russia holds a more than 75 per cent stake, which transmits
electric power through the major grids) and by the interregional grid distribution
companies belonging to this grid and other owners of electricity grid facilities. 25 The
given entities are developing the unified grid and are responsible for building its facilities.
Any other entities may also build electricity transmission lines in accordance with the
town planning legislation of Russia and have the right to their technological connection.
Operational dispatch management in Russia’s electric power sector is performed
by an operator organisation (Open Joint-Stock Company Unified Power Grid Systems
Operator, in which the state holds a 100 per cent stake).
21 Article 3 of the Federal Law on Electric Power.
22 Russia–EU Energy Dialogue. Road map for cooperation between Russia and the EU in the
energy sphere up to 2050. Interim report, July 2011; Expert report, 29 July 2011. p. 8.
23 Official site of the Energy Ministry of the Russian Federation: http://minenergo.gov.ru/activity/
powerindustry/powersector/structure/manufacture_principal_views/.
24 According to Article 26 of the Federal Law on Use of Nuclear Power, licensed activities in the
sphere of nuclear power use include: location, construction, operation and shut-down of nuclear
power units, radioactive waste storage facilities, handling of nuclear materials and radioactive
substances, handling of radioactive waste, performance of expert safety examinations (expert
examination of safety feasibility) of nuclear power use facilities and (or) activities in the sphere
of nuclear power use.
25 Article 9, Clause 3 of the Federal Law on Electric Power.
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No licence or other state permit is required for selling and consuming electric
power.
The supply of gas, as one form of energy supply, is carried out in Russia by the
owner of the Unified Gas Supply Network (Open Joint-Stock Company Gazprom, in
which Russia holds over 50 per cent plus one share), owners of regional gas supply
networks and gas distribution systems, and by independent organisations. The owner of
the Unified Gas Supply Network – a complex of gas extraction, transportation, storage
and supply assets – builds, operates, renovates and develops the facilities making up this
system, exercises continuous dispatch control over their operation and that of facilities
of other owners that are connected to the system. 26 No licence or other state permit is
required for supplying gas (apart from for gas extraction).
The owner of the Unified Gas Supply Network (Open Joint-Stock Company
Gazprom) or its 100 per cent subsidiary (Open Joint-Stock Company Gazprom Export)
has the exclusive right to export gas. 27 Licences to exercise this exclusive right are issued
to given organisations in the manner established by the Russian legislation on foreign
trade. Lack of a licence constitutes grounds for the Russian customs authorities to refuse
to permit export of goods. 28
The oil industry includes oil-extraction enterprises, oil-refineries and organisations
transporting oil (Open Joint-Stock Company Transneft, 29 in which Russia holds 100
per cent of the ordinary shares) and petroleum products (Open Joint-Stock Company
Transnefteprodukt, in which Open Joint-Stock Company Transneft holds a 100 per cent
stake). No licence or other such state permit is required for transporting oil and petroleum
products. Neither is any licence or other such state permit required for processing and
selling coal (fuel shale).
According to the Russian legislation, 30 a licence is a special permit for a legal
entity or individual entrepreneur to engage in a specific activity (work or service). The
licence is issued by the relevant licensing authority.
All organisations in the energy sphere that deal with energy resources contained
in the subsoil (including on production sharing agreement terms) require a subsoil use
licence, which specifies the subject of the activities, the designated purpose and types of
work (geological study, exploration and extraction, etc.), the location and description of
the boundaries of the subsoil sector, and so on. 31
26 Articles 13, 14 of the Federal Law on Gas Supply in the Russian Federation.
27 Article 3 of the Federal Law on Gas Export.
28 Articles 24 and 27 of the Federal Law, dated 8 December 2003, No. 164-FZ on the
Fundamentals of State Regulation of Foreign Trade.
29 Also performs trust management of the shares belonging to the Russian Federation in the
independent Caspian Pipeline Consortium.
30 Article 3, Clause 2 of the Federal Law, dated 4 May 2011, No. 99-FZ on Licensing of Certain
Activities.
31 Articles 11 and 12 of Law of the Russian Federation, dated 21 February 1992, No. 2395-I on
the Subsoil; Appendix 4 to the Administration Regulations, approved by order of the Ministry
for Natural Resources of the Russian Federation No. 315 dated 29 September 2009.
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All organisations in the energy sphere that engage in construction require relevant
licences.
Depending on the circumstances and the specific activity, licences may also be
needed for:
a operation of explosion-hazardous production facilities;
b operation of chemically hazardous production facilities; and
c collection, use, decontamination and placement of hazard class I–IV waste.
iii Ownership and market access restrictions
In the electric power sector, at least 75 per cent plus one share of the organisation for
management of the Unified Russian Electricity Grid (Open Joint-Stock Company
Federal Grid Company of the Unified Energy Grid) must belong to Russia. The owner
of an electricity grid belonging to the given network, if it intends to sell it, is required
to notify the given organisation to this effect, indicating the price and other terms of
sale. If the organisation refuses to make the purchase or does not advise of its readiness
to purchase the facility within six months, the owner is entitled to sell it at no lower
than the announced price. If this procedure is violated, the organisation has the right,
within six months of receiving the information about the sale, to make a judicial claim
for the rights and obligations of the facility’s purchaser to be transferred to it. The given
organisation and its affiliates are prohibited from selling and purchasing electric power
and capacity. 32
The operational dispatch management organisation (Open Joint-Stock Company
Unified Energy Grid Systems Operator) must be 100 per cent owned by the state. The
systems operator and its affiliates are prohibited from producing, selling and purchasing
electric power. 33
The body for state management of nuclear energy use (State Corporation for
Nuclear Power ‘Rosatom’) is a non-commercial organisation with a 100 per cent property
contribution by Russia. 34 The main nuclear power joint-stock company (Open Joint-
Stock Company Nuclear Energy-industrial Complex) belongs 100 per cent to Russia
or the aforementioned state management body. This company and those it controls
conclude transactions with their shares in nuclear power complex organisations with the
permission of the President of Russia, the Russian government and, in a number of cases,
with the consent of the above-mentioned state management body. Transactions lacking
such consent are null and void. 35 Nuclear materials, nuclear installations, radiation
32 Article 8, Clauses 2–4 of the Federal Law on Electric Power.
33 Article 12, Clauses 3 and 4 of the Federal Law on Electric Power.
34 Article 3, Clause 1 of the Federal Law on the State Corporation for Nuclear Power ‘Rosatom’.
35 Article 4, Clauses 18 and19 of Federal Law dated 5 February 2007 No. 13-FZ on the specifics
of management and disposal of property and shares of organisations operating in the sphere
of nuclear power use; Section III, Clause 16 of the Articles of Association of Open Joint-Stock
Company Nuclear Energy-industrial Complex.
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sources and radioactive substances are owned by Russia and, in particular cases and
within certain limits, by Russian legal entities. 36
In the gas power industry, Russia must hold at least 50 per cent plus one of
the total ordinary shares possessed by Russia and by joint-stock companies in which
Russia has a more than 50 per cent stake in the organisation that owns the Unified Gas
Supply Network (Open Joint-Stock Company Gazprom). It is prohibited to divide up
the Unified Gas Supply Network. Ordinary shares in the owners of each regional gas
supply and gas distribution network that may belong to foreign organisations are limited
to a maximum of 20 per cent. 37
As previously mentioned, the owner of the Unified Gas Supply Network or the
100 per cent owned subsidiary of this owner (Open Joint-Stock Company Gazprom
Export) has the exclusive right to export gas. 38
iv Transfers of control and assignments
Organisations rendering the following services are natural monopoly entities: electric
power transmission, operational dispatch management in the electric power sector, gas
transportation by gas pipeline, and oil and petroleum product transportation by major
pipeline. Such organisations and those dealing with energy resources contained in the
subsoil (geological study, exploration and extraction of minerals on subsoil sectors of
federal significance) are classed as being of strategic significance for the country’s defence
and security. 39 Consequently, restrictions have been imposed on foreign investors and
groups of entities, including a foreign investor participating in the authorised capitals of
such organisations and concluding transactions entailing control over them.
Foreign states, international organisations, and foreign and Russian organisations
under their control do not generally have the right to establish direct or indirect control
over Russian strategic organisations. Transactions concluded thereby to acquire the rights
to dispose of over 25 per cent of the votes in Russian strategic organisations (more than 5
per cent of the votes if subsoil sectors of federal significance are used) are subject to prior
agreement with the Russian state.
Other foreign investors (including foreign and Russian organisations under their
control) may, in principle, establish direct or indirect control over Russian strategic
organisations but must obtain prior approval for acquiring the rights to determine
decisions made by such organisations and to dispose, directly or indirectly, of more than
50 per cent of the votes in such an organisation (25 per cent or more of the votes if
subsoil sectors of federal significance are used). 40
36 Article 5 of the Federal Law on Use of Nuclear Power.
37 Articles 15, 14 and 7 of the Federal Law on Gas Supply in the Russian Federation.
38 Article 3 of the Federal Law on Gas Exports.
39 Article 3, Part 1 Clause 2 and Article 6, Clauses 36 and 39, of the Federal Law on Foreign
Investment in Companies of Strategic Importance for National Defence and Security.
40 Article 2, Part 3 and Article 3 Part 1 Clause 3 of the Federal Law on Foreign Investment in
Companies of Strategic Importance for National Defence and Security.
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Decisions on prior approval of transactions involving control by foreign investors
over Russian strategic organisations are made on the basis of applications from the
foreign investors by the government commission for control over foreign investment in
the Russian Federation, are valid for the term established therein, are executed by the
anti-monopoly authority of Russia and forwarded to the investor. A decision may be
taken, in particular, on a condition on agreement with the investor that it fulfil certain
obligations (for example, to render services at a price set in accordance with the Russian
legislation on natural monopolies or to process the minerals extracted within Russia).
It usually takes three months for an application to be considered (with the possibility
of extension for another three months). Transactions entered into by foreign investors
in relation to Russian strategic organisations in violation of the established procedure
for their prior approval are null and void (with application of the consequences of the
invalidity of a void transaction and the possibility of the foreign investor being deprived
judicially of its voting rights attached to shares and stakes exceeding the set limits).
Also envisaged is the obligation of foreign investors to furnish the anti-monopoly
service of Russia with information on acquisition of 5 per cent or more of the shares
(stakes) in Russian strategic organisations. 41
The Russian organisations in the energy sphere that are natural monopoly entities
are covered by the restrictions applicable to such organisations.
The body that regulates natural monopolies (the Federal Monopoly Service)
approves, on the basis of a mandatory application from a natural monopoly entity:
a transactions to acquire title or use rights to fixed assets with a balance sheet value
of over 10 per cent of its equity capital not intended for production (sale) of
regulated goods (services);
b investments in production (sale) of unregulated goods (services) accounting for
over 10 per cent of its equity capital;
c sale, lease or other transaction on acquiring title or use rights to part of its fixed
assets with a balance sheet value of over 10 per cent of its equity capital intended
for production (sale) of regulated goods (services). 42
An entity or group of entities that has acquired, under any transaction, more than 10 per
cent of the votes in a natural monopoly entity must notify the body regulating natural
monopolies (the Federal Anti-monopoly Service) to this effect and of all changes in the
number of votes. The same obligation is borne by a natural monopoly entity acquiring
more than 10 per cent of the votes in another commercial entity. 43
Acquisition of shares (stakes) in organisations in the energy sphere and acquisition
thereby of shares (stakes) in other commercial entities are covered by the general
restrictions of the anti-monopoly legislation in relation to economic concentration
(incorporation, merger, absorption of organisations, transactions with their shares
41 Article 14 of the Federal Law on Foreign Investment in Companies of Strategic Importance for
National Defence and Security.
42 Article 7, Clause 2 of the Federal Law on Natural Monopolies.
43 Article 7, Clause 4 of the Federal Law on Natural Monopolies.
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Russia
or property). Exercise of state anti-monopoly control (obtaining prior approval from
and subsequent notification of the Federal Anti-monopoly Service) for the purpose of
protecting competition depends on the way the authorised capital is paid at the time of
incorporation, on the dominant provision, the total value of the assets or revenues of the
organisation (or group of entities), and the size of the stake acquired in the organisation.
The legislation provides for negative implications of violating the procedure for obtaining
prior approval or submitting a subsequent notification. 44
For example, in relation to the electric power wholesale and retail markets, it
is established that anti-monopoly regulation applies to prices, economic concentration
on the wholesale market, redistribution of the shares (stakes) and property of wholesale
market participants, and so on. 45
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
The reform of the Russian electric power industry set the aim of dividing up the spheres
of activity within it, depending on their nature, into ones with competitive potential
(production, sale and consumption of electric power) and ones relating to natural
monopolies (transmission of electric power, operational dispatch management in the
electric power sector). In the main, this has been successfully completed, since the
division has been carried out and organisations have been set up with horizontal rather
than vertical integration in the relevant spheres.
Production of electric power has been concentrated in wholesale market generating
companies and territorial generating companies engaged mainly in thermal generation.
Generating companies are, however, very big, with all electric power production at
big hydropower plants belonging to a single company. The nuclear power industry,
including generation of electricity, remains a unified production complex, again of a
single company.
The reform has also made possible foreign participation in Russian organisations
producing electric power, the stakes of foreign companies in a number of cases being
dominant. For instance, the company E.ON holds 82.3 per cent of the shares in the
wholesale generating company E.ON Russia (formerly OGK-4), Enel holds 56.43 per
cent of the wholesale generating company Enel OGK-5 (formerly OGK-5), and Fortum
holds 94.51 per cent of the territorial generating company Fortum OJSC (formerly
TGK-10) and 25.66 per cent of the territorial generating company Open Joint-Stock
Company TGK-1.
At the same time, there has been a strengthening of state control and unity of
management in the natural monopolies – transmission of electric power and operational
dispatch management in the electric power sector.
44 Chapter 7 of Federal Law dated 26 July 2006 No. 135-FZ on Protection of Competition.
45 Article 25, Clause 2 of the Federal Law on Electric Power.
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Russia
Electric power sales companies are not classed as natural monopoly entities in
Russia, though many of them remain large enough to influence this sales market.
Production of electric power in the gas industry is consolidated in a vertically
integrated company – Limited Liability Company Gazprom Energoholding (a 100 per
cent subsidiary of Open Joint-Stock Company Gazprom). The company holds over 50
per cent in the open joint-stock generating companies Mosenergo, OnGK-2 (including
the recently absorbed OGK-6) and TGK-1.
Predominant within the structure of the oil industry are approximately 10 major
vertically integrated open-joint stock companies (Rosneft, Lukoil, Surgutneftegaz, TNK-
BP, Gazprom oil and others), almost all of which are privately owned, with a substantial
foreign stake.
Since the coal industry was privatised and restructured, all coal is mined by privatelyowned
organisations. Moreover, these have being gradually undergoing concentration,
the result being formation of 16 big holding companies with an approximate 80 per
cent share in all coal mining. A special place among these is occupied by five coal-steel
companies that mine virtually all the coking coal and use it as an energy source for metal
production.
ii Transmission/transportation and distribution access
The main principles of state regulation and control in the electric power sector include
provision of non-discriminating access to:
a the services of natural monopoly entities in the electric power sector;
b the services of organisations within the commercial infrastructure of the wholesale
market;
c information on the functioning of the wholesale and retail markets; and
d information on the activities of participants in the electric power industry. 46
In this connection, on the territory of Russia, the following have been unified:
a Rules for non-discriminating access to electric power transmission services and
provision of these services;
b Rules for non-discriminating access to operational dispatch management services
in the electric power sector and provision of these services;
c Rules for non-discriminating access to the services of the administrator of the
wholesale market trading system and provision of these services; and
d Rules for technological connection of energy-receiving devices belonging to
electric power consumers, of electric power production facilities and electricity
grid facilities to electricity grids. 47
In the sphere of gas supply to organisations owning gas supply networks, it is prohibited
to create barriers to independent organisations accessing the gas market. 48 A procedure
46 Article 20, Clause 1 of the Federal Law on Electric Power.
47 Resolution of the Government of the Russian Federation No. 861 dated 27 December 2004.
48 Article 26 of the Federal Law on Gas Supply in the Russian Federation.
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Russia
has been approved for non-discriminatory access for independent organisations to gas
transportation and distribution networks – the gas transportation system of Open
Joint‐Stock Company Gazprom 49 and local gas distribution networks. 50 Access is
provided given free capacity in the network.
In accordance with the legislation on natural monopolies, non-discriminatory
access has also been established to oil and petroleum product transportation services
via major pipelines for the purpose of oil and petroleum product consumption on the
Russian domestic market and for their export. 51 In providing access, the through capacity
of the pipelines is taken into consideration.
iii Rates
The following are applied to all natural monopoly entities in the energy sector and in
other cases envisaged by law:
a price regulation;
b identification of consumers subject to mandatory provision of services (nondisconnectable);
and
c regulation of investment and other regulation methods. 52
State regulation of prices (tariffs) in the electric power sector must ensure an economically
reasonable rate of return on capital invested in performance by electric power companies of
regulated activities. At the same time, consumers must be protected against unreasonably
high prices (tariffs) for electric power (capacity). Price (tariff) setting must take account
of how the legislation on energy saving and raising energy efficiency is observed. 53
The government establishes the fundamentals for price-setting in the sphere of
regulated prices (tariffs) in the electric power sector and the rules for state regulation
(review and application) of prices (tariffs) in the electric power sector. At the same time,
regulated prices (tariffs) may be set either numerically or as a formula or procedure for
determining such prices. 54
The objective is to achieve a balance of economic interests of suppliers and
consumers of electric power. This means accessibility of electric power with full recovery
of invested capital in regulated spheres of activity in consideration of an economically
49 Resolution of the Government of the Russian Federation, dated 14 July 1997, No. 858.
50 Resolution of the Government of the Russian Federation, dated 24 November 1998, No. 1370.
51 Resolution of the Government of the Russian Federation, dated 29 March 2011, No. 218;
Article 6 of the Federal Law on Natural Monopolies.
52 Article 6 of the Federal Law on Natural Monopolies; Article 9, Clause 3 of the Federal Law on
Electric Power.
53 Articles 6 and 20, and Article 23, Clause 2 of the Federal Law on Electric Power.
54 Article 23, Clause 1 of the Federal Law on Electric Power; Fundamentals of price setting in
the sphere of regulated prices (tariffs) in the electric power sector and Rules for state regulation
(review, application) of prices (tariffs) in the electric power sector, approved by resolution of the
Government of the Russian Federation, dated 29 December 2011, No. 1178.
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Russia
reasonable return (with separate accounting of output and expenditures related to
production costs).
From 2010–2012, long-term tariffs are set for electric power transmission services
rendered by the unified national and territorial grid companies, on the basis of long-term
parameters for regulation of their activities, including by applying a method for ensuring
a return on invested capital. 55 These companies are required to attain goods and services
reliability and quality parameters stipulated by the government, otherwise the long-term
parameters are subject to adjustment.
Approved prices (tariffs) in the electric power sector are valid for a minimum of
12 months, unless the government decides otherwise.
In the sphere of gas supply, the government establishes the principles for setting
gas prices and the tariffs for transporting it along gas transportation (main) and gas
distribution networks. State regulation of these prices and tariffs takes into consideration
economically reasonable expenditures and profits, as well as the finances available to gas
supply network owner companies for expanding gas extraction, gas pipeline networks
and underground gas storage facilities. 56
The state has approved the tariffs for the services rendered by owners of gas
distribution networks for transporting gas and the procedure for applying them. Tariffs
may be differentiated in consideration of the economic and social gas supply conditions
on parts of the territories of constituent entities of the Russian Federation.
A transition period from 2011 through 2014 has been set for introducing market
principles for setting prices for gas supplied by Open Joint-Stock Company Gazprom
and its affiliates (in consideration of achieving equal returns on gas supplies to both
the foreign and domestic markets and of the cost of alternative fuels), and preparing
for transition from state regulation of gas wholesale prices to state regulation of gas
transportation tariffs via major gas pipelines.
iv Security and technology restrictions
The legislation focuses particularly on ensuring the safety of fuel and energy complex
facilities in Russia – those in the electric power, oil extraction, oil refining, petrochemical,
gas, coal, shale and peat industries, gas supply, petroleum product supply and heat supply.
55 Order of the Federal Tariff Service dated 30 March 2012 No. 228-e on approval of
Methodological Instructions for regulating tariffs using the investment capital return method.
56 Articles 8, 21 and 23 of the Federal Law on Gas Supply in the Russian Federation; Main
provisions on setting and state regulation of gas prices and tariffs for its transportation on
the territory of the Russian Federation, approved by resolution of the Government of the
Russian Federation dated 29 December 2000 No. 1021; Methodology for calculating tariffs
for gas transportation along main gas pipelines, approved by order of the Federal Tariff Service
dated 23 August 2005 No. 388-e/1; Methodological Instructions for regulating tariffs for gas
transportation along gas distribution networks, approved by order of the Federal Tariff Service
dated 15 December 2009 No. 411-e/7.
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The main aim is to prevent any unlawful intervention and to provide physical and other
protection for these facilities. 57
In normal circumstances, the safety of such facilities is ensured by their owners or
other lawful holders, either individuals or legal entities.
In order to protect facilities against terrorism, facility security passports are drawn
up. For differentiating between the safety requirements of facilities, the latter are divided
up into three danger categories (high, medium and low). Only a Russian legal entity
may be the owner or other lawful holder of a high danger category facility. Physical
protection of such a facility is implemented right from the construction stage. Approval
is required from competent federal executive authorities for lease or transfer for other
non-productive use of a high danger category facility or part of it and the land plots on
which they are located. Owners of high danger category facilities have to insure liability
for causing harm to health, life and property of third parties as a result of an accident,
terrorist act or sabotage.
A state information system for the fuel and energy complex (by branch, with an
integration segment for inter-system interaction and a state operator) is being formed
to cover the whole country. The system will contain information on the status of this
complex and forecasts of its development (including on actual and forecast reserves of
mineral energy sources). 58 Owners of the facilities making up this complex must set
up within them systems for protecting information and information networks against
unlawful access to the information, destruction of information and other unlawful
actions.
IV
ENERGY MARKETS
i Development of energy markets
In Russia, the market for electric power and capacity and the gas market function
separately.
There is a wholesale and a retail market for electric power and capacity.
The commodities on the wholesale market consist of electric power and capacity.
They are traded within the framework of the Unified Power Grid of Russia, with the
participation of major producers and purchasers of these and other wholesale market
participants in accordance with the rules governing the wholesale market. Retail markets
are where electric power is traded as a commodity outside the wholesale market, with the
participation of electric power consumers. 59
57 Federal Law on Safety of Fuel and Energy Complex Facilities; Federal Law dated 21 July 1997
No. 117-FZ on Safety of Hydro-engineering Structures.
58 Federal Law on the State Information System for the Fuel and Energy Complex.
59 Rules for the electric power and capacity wholesale market, approved by resolution of the
Government of the Russian Federation, dated 27 December 2010, No. 1172; Basic provisions
for the functioning of electric power retail markets, approved by resolution of the Government
of the Russian Federation, dated 31 August 2006, No. 530.
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Russia
There is a unified legal framework for formation of the gas market. 60 For the
purpose of developing market principles for setting gas prices, part of the natural gas on
the Russian domestic market must be sold on commodity exchanges. 61
ii Energy market rules and regulation
In the electric power sector, the government determines: 62
a electric power and capacity wholesale market price zones – areas for which an
equilibrium wholesale market price is formed; 63
b electric power and capacity wholesale market non-price zones – areas in which
the wholesale trade in electric power (capacity) is conducted at regulated prices
(tariffs); and
c technologically isolated territorial electric power grids – energy networks with no
technological connection to the Russian Unified Power Grid. 64
The legislation establishes in which cases electric power (capacity) prices in the electric
power sector and those for services rendered on the wholesale and retail markets are
subject to state regulation. 65
In the gas supply sphere, state pricing policy is designed to:
a create favourable conditions for seeking, exploring and developing gas deposits,
extracting, transporting, storing and supplying gas;
b
c
expand the sphere of application of market prices to gas;
exercise control over application of state regulated prices (tariffs) in the gas supply
sphere (the tariffs may be differentiated in consideration of the economic and
social conditions in the various Russian regions);
d reimburse the organisation owning the gas supply network for gas payment debts
incurred by non-disconnectable consumers ;
e encourage use of gas as a motor fuel; and
f ensure the competitiveness of Russian gas on the world energy market. 66
60 Article 16 of the Federal Law on Gas Supply in the Russian Federation.
61 Resolution of the Government of the Russian Federation dated 16 April 2012 No. 323 on sale
of natural gas on commodity exchange.
62 Article 3 of the Federal Law on Electric Power.
63 Two such zones have been identified: Europe and the Urals; Siberia (see Appendix No. 1 to
the Rules for the electric power and capacity wholesale market, approved by resolution of the
Government of the Russian Federation, dated 27 December 2010, No. 1172).
64 Seven such systems have been determined: Kamchatka Territory; Magadan Region; western
region of the Republic of Sakha (Yakutia); central region of the Republic of Sakha (Yakutia);
Sakhalin Region; Chukotka Autonomous Area; Taimyr (Dolgano-Nenets) Autonomous Area
(see the list approved by resolution of the Government of the Russian Federation dated 27
December 2004 No. 854 on approval of the Rules for operational dispatch management in the
electric power sector).
65 Article 23.1 of the Federal Law on Electric Power.
66 Article 20 of the Federal Law on Gas Supply in the Russian Federation.
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iii
Contracts for sale of energy
Russia
A system of electric power and capacity sale and purchase agreements, including bilateral
ones, and their registration is envisaged in the electric power sphere. The government
approves the rules for concluding and fulfilling public contracts on the wholesale and retail
markets and those for technological connection to the electricity grids, provision of electric
power transmission and operational dispatch management services in the electric power
sector, as well as sample agreements with consumers for sale and purchase of electric power
(electricity supply). Suppliers and purchasers of electric power are entitled to conclude
agreements containing elements of different types of contract (mixed agreements).
Gas is supplied on the basis of agreements between suppliers and consumers in
accordance with the civil legislation and the rules approved by the Russian government
for gas supply and for use of gas in Russia, as well as other legal acts.
The pre-emptive right to conclude gas supply agreements is enjoyed by purchasers
of gas for state and municipal needs, utility, domestic and social needs of the people, and
by buyers with which existing gas supply agreements are prolonged. Sellers and buyers of
gas have the right to its transportation.
Special conditions are envisaged in agreements between gas, electricity and heat
supply organisations.
iv Market developments
Within the framework of the objective restrictions on the electric power market,
opportunities are being sought for specifying its configuration and development.
On the gas market, the focus is increasingly on exchange trade in gas.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
According to Russian legislation, renewable energy resources consist of solar, wind, water
(excluding power produced by hydroelectric power plants), tidal, wave and geothermal
power, low-potential thermal energy of the earth, air, water, biomass, biogas, gas from
production and consumption waste at landfill sites and gas from coal workings. 67 Rules
have been adopted under which a generating facility is classed as using renewable energy
resources. 68 Subsidies are granted out of the federal budget for technological connection
of such facilities up to 25MW to electricity grids. On the wholesale market, a markup
is added to the price of electric power generated by facilities using renewable energy
resources in order to encourage such production. To compensate for losses in the grid, grid
organisations have to acquire electric power primarily from the given generating facilities.
67 Article 3 of the Federal Law on Electric Power.
68 Rules for classing a generating facility functioning on the basis of renewable energy resources,
approved by resolution of the Government of the Russian Federation, dated 3 June 2008, No.
426.
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Information about use of renewal energy sources (including relevant generating
facilities) is included in the state information system for the fuel and energy complex.
ii Energy efficiency and conservation
Energy efficiency means the ratio of the useful effect from using energy resources to the
cost of obtaining them.
In Russia, requirements are set on the energy efficiency of buildings, structures,
goods, work and services, rules adopted for determining the energy efficiency class
of individual goods and apartment blocks, and bans or restrictions introduced on
production and circulation of certain goods with a low energy efficiency. Facilities are
equipped with energy resource consumption meters, energy inspections are carried out,
energy passports drawn up for facilities and energy servicing agreements concluded for
the purpose of energy saving and efficient use of energy resources by the customer.
In a number of cases, expenditure to save energy and increase the energy efficiency
of organisations engaged in regulated types of activity is taken into account when the
prices (tariffs) are set for goods and services (including for capital investment).
iii Technological developments
Technical and technological development in the sphere of use of renewable energy
resources in Russia is lagging behind the global level, partly because there are substantial
non-renewable energy resources.
VI
THE YEAR IN REVIEW
In the course of liberalisation of the electric power sphere, certain problems have been
identified in providing a competitive environment and setting and holding down electric
power prices (tariffs). In the gas power industry, the focus has turned to exchange trade in
gas for the purpose of determining market prices for gas. Practical steps are being taken
to launch gas and oil extraction on Russia’s shelf. The coal power industry retains its
importance, but certain positive results have been achieved in energy saving and raising
energy efficiency.
VII
CONCLUSIONS and OUTLOOK
The energy sector and energy resources remain the mainstay of the Russian economy,
securing its important position on the international energy markets.
Russia will undoubtedly continue to focus intently on its own national and the
international energy sectors.
236

Chapter 20
South Africa
Shamilah Grimwood and Zahra Omar 1
I
OVERVIEW
i Electricity
South Africa has a gross installed electricity generation capacity of about 36GW
dominated by coal-fired electricity generation facilities (90 per cent). Electricity
production from hydro, natural gas and oil sources located in South Africa is nominal
(about 1 per cent). Nuclear electricity production (from the Koeberg power station,
South Africa’s only nuclear power station) is estimated at 5 per cent, with South Africa
importing the balance of its electricity consumption requirements mainly from the
Cahora Bassa hydro-power plant in Mozambique and otherwise through the regional
power exchange among members of the Southern African Power Pool. South Africa has
over 400,000 kilometres of distribution network infrastructure plus 26,225 kilometres
of transmission lines with a nominal voltage above 132kV. Its network infrastructure
with a nominal voltage of 132kV or less comprises its distribution asset base.
In March 2011, Eskom Holdings SOC Limited (‘Eskom’), 2 the national electricity
supply utility, reported that South Africa’s reserve margin had improved to 14.9 per cent
(up from 5 per cent in January 2008 when South Africa experienced severe blackouts
reportedly due to constraints in coal supply and technical outages). South Africa’s current
20-year new generation capacity plan proposes to more than double its installed capacity
by 2030 by adding nearly 53GW. The generation mix of the proposed new generation
capacity plan allocates 16.3GW for coal, 9.6GW for nuclear, 17.8GW for renewables
and 8.9GW for other generation sources.
1 Shamilah Grimwood is a partner and Zahra Omar is a senior associate at White & Case LLP
(South Africa).
2 Established in terms of the Eskom Conversion Act 3 of 2001.
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South Africa’s electricity industry is characterised by a vertically integrated supply
chain with the substantial majority of its generation, transmission and distribution assets
being owned and operated by Eskom. Recent and pending revisions to the regulation
of the electricity industry have focused on the opening up of generation through the
facilitation of investment by independent power producers (‘IPPs’) and the transfer of
Eskom’s transmission assets and activities, including the operation of the integrated
transmission system, to an independent system and market operator (‘ISMO’).
In August 2011, the Department of Energy issued a request for qualification
and proposals for new generation capacity under an IPP procurement programme
for renewable energy generating capacity 3 (to be sourced from onshore wind, solar
photovoltaic, concentrated solar power, biomass, biogas, landfill gas and small hydro –
‘the RE-IPP Procurement Programme’) totalling 3.65GW. Eskom has been designated by
the Minister of Energy as the single buyer for all electrical energy produced pursuant to
this programme. Eskom also commenced its own tender programme for the construction
of a 100MW onshore wind project in 2011, which Eskom will own and operate. The
targeted commercial operation date for these projects ranges between June 2014 and
December 2016.
ii Coal
South Africa’s primary energy resource base is dominated by coal (77 per cent). Apart
from extensive domestic consumption including in the generation of electrical energy
(Eskom ranks first in the world as steam coal user and seventh as electricity generator),
about 28 per cent of domestic coal production is exported with South Africa being one
of the five largest coal-exporting countries in the world. Just over 51 per cent of South
Africa’s coal mining is done underground, the balance is done using open-cast mining.
Given changes in South Africa’s coal supply market towards global commodity
pricing and to facilitate its carbon emission reduction commitments, national energy
policy is keenly focused on significantly reducing the use of coal in the country’s electricity
generation mix. South Africa’s current 20-year new generation capacity plan proposes to
reduce coal participation in the electricity generation mix to 65 per cent.
iii Natural gas
South Africa’s fledgling upstream natural gas industry has limited potential. To date there
have been no onshore natural gas discoveries in South Africa. Domestic natural gas does
not form part of the country’s mainstream energy supply. South Africa has no gas-fired
electricity generation, however, its operational OCGT capacity which uses kerosene or
diesel-fired systems may be converted to gas-fired systems.
3 To date this is only the second procurement for new generation capacity from IPPs undertaken
by the South African government acting through the Department of Energy. The first
procurement for diesel-fired peaking power (1GW), which commenced in April 2006 has not
yet achieved financial close following delays linked to the withdrawal of the first preferred bidder,
the 2008–2009 global financial crisis and changes to the electricity regulatory framework.
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Natural gas is imported into South Africa from Mozambique. The governments
of Mozambique and South Africa, together with the pipeline operator, own the Temane–
Secunda pipeline through a joint venture. Gas imports from Mozambique via this
pipeline provide the 4 per cent natural gas contribution to South Africa’s primary energy
resource base.
iv Oil
As with natural gas, South Africa’s fledgling upstream oil industry has limited potential.
South Africa imports all its crude oil requirements.
Domestic demand for liquid fuels is met by synthetic fuels (36 per cent) produced
locally mainly from coal and the balance by liquid fuels produced locally from the
refinement of imported crude oil (76 per cent). South Africa has limited diesel-fired
electricity generation (less than 0.1 per cent used for peak and emergency loads).
II
REGULATION
i The regulators
The key regulators of the South African energy industry are the Minister of Minerals, the
Minister of Energy, the National Energy Regulator of South Africa (‘NERSA’) and the
Controller of Petroleum Products.
The Minister of Minerals is responsible for the overall regulation of all upstream
activities in the minerals and petroleum sectors: prospecting, exploration, mining and
production. This responsibility entails the articulation of national government policy
and the making of subordinated or delegated legislation through regulations and notices
as permitted under primary legislation (that is, legislation enacted by Parliament).
The Minister is supported in this function by the Department of Minerals. Upstream
activities in the minerals and petroleum sector are primarily governed by:
a Mineral and Petroleum Resources and Development Act (‘the MPRDA’); 4
b Mineral and Petroleum Resources Development Regulations (‘the MPRD
Regulations’); 5 and
c Mineral and Petroleum Resources Royalty Act (‘the MPRRA’). 6
It should be noted that significant amendments to the MPRDA have been enacted
pursuant to the Mineral and Petroleum Resources Development Amendment Act 7 but
these amendments are not yet in effect.
The Minister of Energy is responsible for the overall regulation of all downstream
activities, including electricity generation, transmission and distribution; the transmission,
distribution, storage, liquefaction, re-gasification and trading in gas transported by
pipeline; the construction and operation of petroleum pipelines, petroleum marine
4 Act 28 of 2002.
5 Promulgated in GN R527 in GG 26275 of 23 April 2004.
6 Act 28 of 2008.
7 Act 49 of 2008.
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loading facilities and petroleum bulk storage facilities; and all downstream supply chain
activities in respect of petroleum products. This responsibility entails the articulation
of national government policy and the making of subordinated or delegated legislation
through regulations and notices as permitted under primary legislation. The Minister is
supported in this function by the Department of Energy. These downstream activities are
primarily governed by the following laws:
a the Electricity Regulation Act (‘the ERA’); 8
b the Integrated Resource Plan for Electricity 2010–2030 (‘the IRP 2010–2030’); 9
c the Electricity Regulations on New Generation Capacity (‘the Electricity
Generation Regulations’); 10,11
d the National Energy Regulator Act; 12
e the Gas Act; 13
f the Gas Regulator Levies Act; 14
g the Gas Act Rules; 15
h the Petroleum Pipelines Act; 16
i the Petroleum Pipelines Levies Act; 17 and
j the Petroleum Products Act. 18
Some legislative amendments are currently before the National Assembly for consideration
that will significantly overhaul the aforementioned legislation. These include:
a the Electricity Regulation Second Amendment Bill (‘the ERA Amendment
Bill’); 19
8 Act 4 of 2006.
9 Electricity Regulations on the Integrated Resource Plan 2010–2030 (GN R400 in GG 34263
of 6 May 2011).
10 Promulgated in GN R399 in GG 34262 of 4 May 2011.
11 In addition to the above legislation, the electricity sector is also governed by the Constitution of the
Republic of South Africa, 1996 (the Constitution), which grants municipalities executive authority
and the right to administer electricity reticulation; the Eskom Conversion Act 13 of 2001, which
provides for Eskom’s status as a public company generally subject to company laws, under 100 per
cent state ownership (through the Ministry of Public Enterprises) and liable for the payment of
dividends and taxes; Local Government: Municipal Finance Management Act 56 of 2003, which
prescribes the framework of fiscal management of municipal entities such as municipal electricity
utilities; and the Local Government: Municipal Systems Act 32 of 2000, which prescribes the
framework for the municipal administration of electricity reticulation and tariffs.
12 Act 40 of 2004.
13 Act 48 of 2001.
14 Act 75 of 2002.
15 Gas Act Rules 2009 (GN R1251 in GG 32849 of 31 December 2009).
16 Act 60 of 2003.
17 Act 28 of 2004.
18 Act 120 of 1977.
19 Promulgated in GN 905 in GG 34870 of 19 December 2011.
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b the National Energy Regulator Amendment Bill; 20 and
c the Independent System and Market Operator Bill (‘the ISMO Bill). 21
NERSA currently performs the role of the economic and technical regulator in the
electricity industry (where it is referred to as the National Electricity Regulator), the
downstream piped gas industry (where it is referred to as the Gas Regulator) and the
downstream petroleum pipeline industry (where it is referred to as the Petroleum
Pipelines Regulatory Authority or ‘PPRA’). NERSA is the sole licensing authority for
all licensable activities under the ERA, the Gas Act and the Petroleum Pipelines Act and
regulates the tariffs and charges to be applied by licensees in respect of licensed activities
as well as access to licensed transmission, distribution, pipelines and other facilities in
respect of which licensees are obliged to provide third-party access.
The Controller of Petroleum Products is responsible for the licensing of the
manufacture, wholesale and retail of prescribed petroleum products and the licensing
of sites for the conduct of such licensed retail activities. The Minister of Energy is
responsible for, inter alia, prescribing the minimum and maximum prices at which any
petroleum products may be sold.
ii Regulated activities
Electricity
Currently, the ERA generally requires licences for the operation of any generation,
transmission or distribution facility, the import or export of electricity and the trading of
electricity, except in the case of certain exempted activities. 22
Licence applications must be in a prescribed form and processed in accordance with
a prescribed procedure. The Electricity Regulator must decide the application within 120
days of the later of the expiry of the objection period (if no substantiated objections are
received) or the filing by the applicant of any further information as may be required by
the Electricity Regulator. The applicant must be provided with the reasons for the decision.
Any generation or transmission licence is valid for a minimum of 15 years or such
longer period as the Electricity Regulator may determine. Other licences are valid for
periods determined by the Regulator. An application for the renewal of a licence must be
granted by the Electricity Regulator but may be granted under different licence conditions.
Coal
The MPRDA regulates the issue or grant of reconnaissance permissions, prospecting
rights, retention permits and mining rights in respect of coal and other mineral resources.
No licences are required for the sale of or trading in coal.
20 Promulgated in GN 890 in GG 34825 of 8 December 2011.
21 Independent System and Market Operator Establishment Bill (GN 290 in GG 34289 of 13
May 2011) as amended by the Independent System and Market Operator Bill [B9-2012].
22 Construction and operation of a generation plant for demonstration purposes unless it is
connected to an interconnected power supply, the non-grid connected supply of electricity
unless for commercial use and any generation plant constructed and operated for own use.
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Oil and gas
The MPRDA regulates the issue or grant of technical cooperation permits, reconnaissance
permits, exploration rights and production rights in respect of petroleum.
The manufacture, wholesale or retail of any petroleum fuel or lubricant and the
development of any site for the retail of petroleum products may only be carried out
under a licence from the Controller of Petroleum Products issued in accordance with the
Petroleum Products Act. Such licences are evergreen provided that the licensed activity
remains a going concern and in the case of a site licence there is a valid retail licence for
that site.
The construction and operation of petroleum pipelines, marine loading facilities
and bulk storage facilities (except for those pipeline and facilities which are specifically
excluded) may only be carried out under licence issued under the Petroleum Pipelines
Act. The minimum licence period for these licences is 25 years and the licensee is entitled
to the renewal thereof provided it has complied with its licence conditions.
The construction and operation of gas transmission, storage, distribution and
liquefaction facilities and regasification facilities, the conversion of existing infrastructure
into gas transmission, storage, distribution and liquefaction facilities and regasification
facilities, and the trading in gas may only carried out under licences issued by NERSA
in its capacity as the Gas Regulator. In addition the owner of any operation involving
the production or importation of gas, the transmission of gas for own use and small
biogas projects supplying to rural communities must register such operation with the Gas
Regulator. The licence application process is similar to the process under the Petroleum
Pipelines Act. The minimum licence period for these licences is also 25 years and the licensee
is entitled to the renewal thereof provided it has complied with its licence conditions.
The trading of gas (that is, the sale and purchase of gas as a commodity and
associated services) that is transported by pipeline requires a gas trading licence from the
Gas Regulator under the Gas Act.
iii Ownership and market access restrictions
For all the sectors covered in this chapter, there are no prohibitions or limitations on
foreign ownership of energy assets or licensed activities. Instead, ownership controls
relate to requirements for minimum equity ownership in licensed entities by historically
disadvantaged South African citizens (‘HDSAs’) (that is, requirements for meaningful
economic participation through beneficial equity ownership by South African citizens
qualifying as HDSAs). These requirements are typically incorporated as conditions
under the relevant licence or as contractual obligations in any concessions awarded
by the government for the holding or carrying on of energy supply activities through
public–private partnerships.
Electricity
The ERA currently provides for the Minister of Energy to make regulations setting out
criteria for or prohibiting cross-ownership or vertical and horizontal integration by
generation, transmission or distribution licensees. To date, no such regulations have been
published.
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As noted above, the majority of generation, transmission and distribution assets
are currently owned and operated by Eskom, save for distribution assets which are
majority owned and operated by various local authorities.
The build‐out of new generation capacity targeted under the IRP 2010–2030
anticipates IPP participation particularly for renewable energy and thermal energy (but
excluding nuclear energy). Having regard to earlier statements by the National Cabinet,
it appears that IPP participation is targeted at 30 per cent of the total generation mix
(excluding nuclear energy). National government policy specifically favours the ‘managed
liberalisation’ of the electricity supply market to provide for the staged introduction of IPPs
within a single buyer market in which Eskom (and, following the enactment and coming
into effect of the ISMO Bill, the ISMO) will act as the single buyer of the electrical energy
supplied by the IPPs. Entry into and participation in this single buyer market by IPPs is ‘by
invitation only’ through a procurement process initiated at the discretion of the Minister
of Energy (the regulated single buyer market). Such invitation will likely depend on the
outcome of feasibility studies demonstrating the value for money of IPP ownership and
operation when compared with state-owned producer ownership and operation.
Should the ISMO Bill be enacted and brought into effect, Eskom’s entire
transmission business including assets and system operation and generator dispatch will
likely be transferred to the ISMO whose shareholding will be held by the state acting
through the Minister of Energy. The ISMO Bill reflects government policy to retain
transmission under state ownership and control over the short to medium term.
It also appears that the distribution business, currently under municipalities, will
remain under municipal ownership, except for Eskom’s distribution business which will
either remain with Eskom or be transferred to the ISMO or another organ of state. 23
There has been no significant IPP activity outside the regulated single buyer
market. Historically, this has been attributed to low electricity prices from Eskom
and uncertainty over access to wheeling services by Eskom and municipal distributors
(specifically, the absence of regulated standardised terms and conditions for the provision
of wheeling services). More recently, proposed regulatory amendments that, if enacted
and brought into effect, will require IPPs to obtain the approval of the Minister of
Energy for the construction and operation of commercial generation facilities (regardless
of whether such generation requires wheeling services across state or municipality-owned
networks), 24 have made the growth of significant IPP activity outside the regulated single
buyer market less likely.
23 In October 2006 the Cabinet approved the proposal to create six regional electricity distributors
(‘REDs’). Under this proposal the REDs were to be established as public entities with a majority
ownership (51 per cent) to be held by the state, and not as municipal entities; however, in
September 2007, the Municipal Fiscal Power and Functions Act 12 of 2007 was passed by
Parliament, which, inter alia, permitted a municipality to apply to National Treasury for a
transparent electricity surcharge. The proposal for the REDs was subsequently reviewed by
Cabinet and abandoned in 2011.
24 These amendments are proposed pursuant to the Electricity Regulation Second Amendment
Bill in GN 905 in GG 34870 of 19 December 2011.
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Coal
There are no regulatory criteria for or prohibiting cross-ownership or vertical and
horizontal integration of firms in the coal sector.
The Mining Charter 25 covers minimum equity ownership by HDSAs. The
Mining Charter was developed following extensive consultation between the mining
industry and the government and is essentially a plan for the phased transformation of
that industry, including a minimum ‘meaningful economic participation’ 26 target of 26
per cent for HDSAs in holders of mining rights, minimum targets for the procurement
of goods and services from enterprises whose share ownership is 25 per cent plus 1
held by HDSAs (40 per cent in the case of capital goods, 50 per cent in the case of
consumer goods and 70 per cent in the case of services) by holders of mining rights, and
a minimum employment target for HDSAs in executive to junior management levels of
40 per cent by holders of mining rights, in each case by 2014.
Oil and gas
There are no regulatory criteria for or prohibiting cross-ownership or vertical and
horizontal integration of firms in the gas sector. Nevertheless, NERSA in its capacity as
the Gas Regulator may impose licence conditions on any licence issued by it in terms
of the Gas Act to the effect that the gas transmission, storage, distribution, trading,
liquefaction and regasification activities of vertically integrated gas firms must be
managed separately with separate accounts and no cross-subsidisation. 27
There are no regulatory criteria for or prohibiting cross-ownership or vertical and
horizontal integration of firms in the petroleum sector, except prohibitions on wholesalers of
certain petroleum products holding retail licences (other than for training purposes) under
the Petroleum Products Act. 28 Further, NERSA in its capacity as the PPRA may impose
licence conditions in any licence issued by it in terms of the Petroleum Pipelines Act to
the effect that the petroleum loading, pipeline and storage activities of vertically integrated
firms must be managed separately with separate accounts and no cross‐subsidisation.
iv Transfers of control and assignments
South Africa has a developed competition regime regulating the transfer of assets and
services, which largely aligns with the models applied in Canada, the European Union
and the United States. The primary legislation regulating anti-competitive practices is
the Competition Act. 29
The Competition Act prescribes prior notification to and approval from the
competition authorities established thereunder for mergers and acquisitions meeting
25 Promulgated in GN 838 in GG 33573 of 20 September 2010.
26 The Mining Charter defines ‘meaningful economic participation’ as including the ownership
of shares carrying voting rights and participation in the cash flows of the licensed activity not
applied to finance the acquisition of such ownership.
27 Section 21(1)(c).of the Gas Act 48 of 2001.
28 Section 2A(5)(a) of the Petroleum Products Act 120 of 1977.
29 Act 89 of 1998.
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prescribed thresholds. These competition authorities include the Competition
Commission, which is responsible for processing notification and approval applications
and investigating mergers and acquisitions and the Competition Tribunal, which receives
recommendations from the Competition Commission in relation to large mergers and
acts as a court of first instance in adjudicating competition complaints.
The Competition Act recognises the concurrent jurisdiction of the Competition
Commission in relation to industries having their own regulatory authorities. It does so
on the basis that the Competition Commission will exercise primary authority to detect
and investigate alleged prohibited practices and review mergers within any industry or
sector while any other regulatory authority will exercise primary authority to establish
conditions within the industry it regulates as required to give effect to the relevant
legislation in terms of which that regulatory authority functions. 30
The focus of a merger review is whether or not the particular market, post merger,
will likely be less competitive and, if so, whether there is any technological, efficiency or
other pro-competitive gain that off-sets the anti-competitive effect of the merger.
No intermediate or large merger 31 may be implemented without the approval
of the Competition Commission. The Competition Commission has the power to
disallow intermediate mergers and to make any recommendations to the Competition
Tribunal on large mergers. In the case of an intermediate merger the Competition
Commission must respond within 20 business days from the date of submission of the
merger notification in the prescribed form. The Competition Commission may extend
the period for its response by notice to the party submitting the merger notification
given within that period, by up to 40 business days. The Competition Commission may
either approve the intermediate merger conditionally or unconditionally or prohibit it.
In the case of a large merger the Competition Commission must forward the merger
notification, together with its recommendations, to the Competition Tribunal within 40
business days from the date of submission of the merger notification in the prescribed
form. The Competition Commission may extend the period for such referral by notice
to the party submitting the merger notification for further periods of up to 15 business
days each. The Competition Tribunal may either approve the large merger conditionally
or unconditionally or prohibit it.
All licences issued by NERSA may be issued with conditions regarding the sale,
transfer, cessation, assignment and encumbrance of these licences by the holder. The
ERA, the Gas Act and the Petroleum Pipelines Act all prohibit the sale, transfer, cessation
or assignment of licences issued pursuant thereto.
30 Id.
31 An intermediate merger occurs where the value of the proposed merger equals or exceeds 560
million rand (calculated by either combining the annual turnover of both firms or their assets),
and the annual turnover or asset value of the transferred/target firm is at least 80 million rand.
A large merger occurs where the combined annual turnover or assets of both the acquiring and
transferred or target firms are valued at or above 6.6 billion rand, and the annual turnover or
asset value of the transferred or target firm is at least 190 million rand (merger thresholds as at
1 April 2009, Competition Commission, www.compcom.co.za/merger-thresholds/).
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In the case of licences issued by the Controller of Petroleum Products pursuant
to the Petroleum Products Act, wholesale and retail licences are not transferable whereas
manufacturing and site licences are transferable. Site licences are transferable with the
transfer of title to the site, subject to the transferee’s compliance with the prescribed
notification conditions in the relevant regulations.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Electricity
As previously discussed, South Africa’s electricity supply industry is characterised by
a vertically integrated supply chain with the substantial majority of its generation,
transmission and distribution assets being owned and operated by Eskom.
Eskom currently carries on each of its generation, transmission and distribution
activities under separate business units or divisions, each separately licensed with its
own separate accounts so that the revenues, costs, liabilities, reserves and provisions for
each business activity may be separately identifiable. Eskom’s transmission business also
houses the unit designated as the system operator, which is responsible for the short-term
reliability of the interconnected power system and dispatch. 32
About 50 to 60 per cent of South Africa’s distribution networks are owned and
operated by municipal authorities all of whom are dependent on Eskom generation for
their electricity supply requirements. The remaining distribution network is owned and
operated by Eskom, except for a nominal portion of the distribution asset base which is
privately owned.
As discussed in Section II.iii, supra, if the ISMO Bill is enacted and brought into
effect, Eskom’s entire transmission business will likely be transferred to the ISMO. It
appears that the distribution business will remain under municipal ownership, except for
Eskom’s distribution business, which will either remain with Eskom or be transferred to
the ISMO or another organ of state. 33
Natural gas
South Africa has imported natural gas from Mozambique via an 865-kilometre transmission
pipeline since 2004. The governments of Mozambique and South Africa, together with
Sasol Limited, 34 own this transmission pipeline through a special purpose company (‘the
32 Proposed changes to Eskom’s operations are underway in terms of the ISMO Bill, which is
further discussed in Section VI, infra.
33 Although the Cabinet formally approved a policy objective to consolidate the ownership and
operation of distribution networks through six REDs in October 2006, this policy was later
formally abandoned.
34 Sasol is a global petrochemical group based in South Africa. Sasol Limited, the holding company
of the Sasol group, is jointly listed on the Johannesburg (symbol SOL) and New York (symbol
SSL) stock exchanges. Sasol’s operations include coal mining in South Africa, production of
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South Africa
Pipeline Company’). Natural gas imports from Mozambique via this pipeline provide the
total 4 per cent natural gas contribution to South Africa’s primary energy resource base.
The government of South Africa and Sasol are parties to a regulatory agreement in
respect of the transmission pipeline, dated 26 September 2001, which is grandfathered
by the Gas Act (‘the Regulatory Agreement’). Pursuant to the Gas Act, the Regulatory
Agreement is binding on NERSA in its capacity as the Gas Regulator, for a period of
up to 10 years from the date on which the natural gas is commercially supplied into
South Africa from Mozambique (‘the Sasol Special Dispensation Period’). 35 The Pipeline
Company holds the transmission licence for this gas transmission pipeline, and has
appointed Sasol to operate and maintain this transmission pipeline.
Prior to 2004, the bulk of South Africa’s modest gas transmission and distribution
network, mostly under Sasol ownership, was used for the supply of gas produced from
coal at Sasol’s facilities in Secunda and Sasolburg. Under the Regulatory Agreement,
Sasol obtained a concession from the government of South Africa guaranteeing that
Sasol’s existing gas networks and its envisaged future network build-outs scheduled
for the first five years after the start of the Sasol Special Dispensation Period would be
licensed by the Gas Regulator.
ii Transmission/transportation and distribution access
Electricity
Under the ERA a licensee in respect of any transmission or distribution facilities must
provide non-discriminatory access to its facilities to all third parties and may not discriminate
between customers or classes of customers regarding access, tariffs and conditions of
service except for objectively justifiable differences approved by NERSA. The provision
of transmission access and services is regulated by the Grid Code, 36 and the provision of
distribution access and services is regulated by the Grid Code and the Distribution Code. 37
These codes set out, inter alia, the minimum technical requirements for connecting
customers (whether generators or load customers) to the grid, the minimum technical
requirements to be met by network owners, and the rights and obligations of the system
operator in respect of maintaining the short-term reliability of the transmission network.
On the face of the ERA (and ignoring the impact of the ERA Amendment Bill),
open-access rules including rules regarding wheeling services should have been developed
by NERSA by now. But since South Africa’s nascent rollout of IPP generation is not being
managed on a first-come first-served basis, but rather staggered through centrally controlled
procurement programmes (on a ‘by invitation only’ basis), and given the apparent policy
natural gas and condensate in Mozambique, production of oil in Gabon and production of
shale gas in Canada.
35 It appears that this period will end in or about 2014.
36 South African Grid Code published by NERSA in July 2010, as updated from time to time,
currently comprising the Preamble, Governance Code, Network Code, System Operation
Code, Metering Code, Transmission Tariff Code and Information Exchange Code.
37 South African Distribution Code published by NERSA in September 2007, as updated from
time to time.
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preference for limiting development of a bilateral electricity supply market, these openaccess
rules have not been developed and the statutory open-access provisions of the ERA
remain untested to date. Wholesale and retail competition does not exist.
Under the Constitution, municipalities have exclusive jurisdiction over electricity
reticulation within their respective municipal boundaries. Generally, as a term of their
distribution licences, municipal distributors have exclusivity over all load customers located
within their respective municipal boundaries. Pursuant to the Constitution 38 a municipality
may impose a surcharge on its service charges and many municipalities impose significant
surcharges on their electricity supply services, which has led to wide disparities in electricity
supply charges imposed on customers taking their electricity supply requirements from
municipalities. This disparity exists not only between customers of different municipalities
but is particularly pronounced between municipal customers and Eskom’s distribution
customers to whom these municipal surcharges do not apply. Regulatory measures at
the national government level to remove distribution pricing and service level disparities
by transferring municipal and Eskom distribution into REDs have been abandoned. 39
Proposed amendments in the ERA Amendment Bill will, if enacted and brought into
effect, remove all doubt as to NERSA’s jurisdiction to approve any municipal surcharges on
distribution tariffs. Such surcharges will be unregulated by NERSA.
Natural gas
Under the Gas Act 40 a licensee of any gas transmission or distribution facilities may
not discriminate between customers or classes of customers regarding access, tariffs and
conditions of service save for objectively justifiable and identifiable differences regarding
matters such as quantity, transmission distance, length of contract, load profile, interruptible
supply or any other distinguishing feature approved by NERSA, as the Gas Regulator.
The Gas Regulator 41 may impose licence conditions within the framework of
requirements listed in the Gas Act including:
a access for third parties to uncommitted capacity on pipelines;
b compulsory negotiations by transmission licensees with third parties regarding
the routing, size and capacity of future pipelines;
c compulsory negotiations by licensees with third parties regarding compression
of existing pipeline capacity and the equitable sharing among customers of cost
savings arising from increased volume; and
d licensees being obligated to allow technically feasible interconnections with gas
suppliers as long as the person requesting the interconnection bears the increased
costs of such interconnection.
38 Section 229.
39 Although the Cabinet approved the proposal to create the REDs in October 2006, REDs were
ultimately abandoned in 2011 following the empowerment of municipalities with respect to
electricity surcharges pursuant to the Municipal Fiscal Power and Functions Act 12 of 2007.
40 Section 22.
41 Section 21.
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This framework is subject to any matters prescribed by regulations made by the Minister
of Energy. The Piped Gas Regulations are relevant here and regulate third-party access to
transmission pipelines, except for the special dispensation arising under the Regulatory
Agreement.
The Piped Gas Regulations prescribe that the allocation mechanism for
uncommitted capacity must comply with the following principles:
a use it or lose it (but taking into account diurnal and seasonal load variances);
b non-discrimination;
c contract lengths; and
d technical feasibility.
The Gas Regulator may, following its receipt of a complaint from any person who is
denied access to a transmission pipeline, determine the uncommitted capacity of the
pipeline and an allocation mechanism consistent with the above stated principles.
The Regulatory Agreement obliges Sasol to supply distributors outside its
distribution areas licensed by NERSA pursuant the Regulatory Agreement, subject to
available uncommitted distribution capacity, and the technical feasibility and economic
viability of the proposed connections. The Regulatory Agreement further obliges Sasol to
ensure mandatory third-party access for green-fields and brown-fields customers purchasing
minimum specified annual gas quantities to specified pipelines including the Mozambique–
South Africa transmission pipeline over the Sasol Special Dispensation Period.
iii Rates
Electricity
Currently, tariffs for electricity (excluding municipal surcharges on municipal
distribution services) are regulated by NERSA, which may set and approve tariffs charged
by licensees. 42 Licensees may not impose electricity supply tariffs that NERSA has not
approved (excluding municipal surcharges on municipal distribution services).
The tariff principles enumerated in the ERA 43 obligate NERSA to enable an efficient
licensee to recover the full cost of its licensed activities including a reasonable margin or
return. NERSA, accordingly, adopts a cost of supply or rate of return methodology.
NERSA’s pricing methodology does not include incentive rates for efficiency gains. In
theory, inefficiencies in supply should not be passed on to customers, and licensees should
therefore not recover any associated costs or losses; however, the regulated methodology
for ensuring that inefficiency losses are not passed through to customers has not been
elaborated on by NERSA and does not appear to be well documented.
Historically, Eskom tariffs used to be among the lowest in the world 44 as they
have been based on the value of its regulatory asset base, which is largely nearly fully
42 Sections 4(a)(ii) and 14(1)(d) of Act 4 of 2006.
43 Section 15.
44 According to the Eskom Annual Report 2009, the cost of electricity in developing countries
belonging to the OECD averaged between 8 and 9 US cents per kWh when compared with the
cost of electricity in South Africa, which was 3 US cents per kWh.
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depreciated. In the case of new connections to transmission and distribution systems,
customer charges are divided between the costs for the supply of dedicated connection
assets and the costs of any upstream augmentation and strengthening works required to
connect new customers. Generally, the customer must bear the costs of dedicated assets
(connection charge) whereas the costs of upstream works are recovered through use of
system charges that are spread across the load customer base (use of system charges).
Eskom Transmission is currently authorised by NERSA to levy a transmission
use-of-system charge on its customers (‘TUOS charge’). TUOS charges are broadly
designed to enable Eskom Transmission to recover the costs of providing, operating and
maintaining the shared components of the transmission system from its general customer
base on the basis of a 50:50 allocation of Eskom’s regulated transmission asset base
allowance between generation customers and load customers. TUOS charges include:
a an annual ‘network charge’ determined by reference to the installed capacity of
the units comprising the generation facility and their location or the maximum
notifiable demand in the case of a load customer; generators located in certain
regions may have negative network charges due to the benefit of adding generation
in these regions and as new generation capacity in these regions is added the
network charges may change;
b a monthly ‘losses charge’ reflecting the relative amount of transmission losses
associated with the specific position of the customer’s generation facility or
electrical installation on the transmission system; and
c a monthly ‘reliability services charge’, which is determined by reference to the
total flow of electricity into and out of the transmission system and the cost to the
system operator of procuring ancillary services for the reliability of the integrated
transmission system.
In addition, an ‘administration and customer services charge’ is being developed for
Eskom Transmission’s customers. The components of the existing TUOS charges are
currently under review by NERSA.
Natural gas
Under the Gas Act, NERSA in its capacity as the Gas Regulator must regulate prices
and may impose licence conditions within a framework of requirements approving
maximum prices for distributors and reticulators where there is inadequate competition
as contemplated in the Competition Act. NERSA must comply with any regulations
made by the Minister of Energy regarding price regulation procedures and principles.
Under its Regulatory Agreement, Sasol’s average gas price to its external customers
is subject to a price cap calculated by reference to a European benchmark price that is
derived from the 12-month rolling average of six European countries’ gas prices weighted
according to Sasol’s market volume profile. If the Sasol volume-weighted average gas price
charged to its external customers exceeds the average European benchmark price in any
year, Sasol is obliged to refund the over-recovery to those customers on an equitable basis.
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The Regulatory Agreement also specifies price caps for specific customer categories
including resellers purchasing annual gas quantities below the prescribed level; 45 greenfield
customers purchasing above 3 million gigajoules per annum; brown-field customers
purchasing in the range of between 2 to 8 million gigajoules per annum; however, the
price cap only applies to additional quantities in excess of the purchase quantities as of
the date of the Regulatory Agreement and from the expiry of the prescribed grace period.
iv Security and technology restrictions
Eskom’s generation, transmission and distribution facilities are classified as ‘national key
points’ under the National Key Points Act. 46 The Act empowers the Minister of Police 47 to
declare any asset or area to be a national key point where such asset or area is so important
that its loss, damage, disruption or immobilisation may prejudice the state or public
interests. The South African Police Service is authorised to provide security regulatory
services in respect of identified national key points, which includes the evaluation of
declared national key points to ensure compliance with security standards. 48
Theft of transmission and distribution assets, such as cables and transmission
tower components, is an ongoing problem resulting in significant financial losses and
electricity outages. 49 However, increased physical security and new security technologies
at Eskom’s substations have seen a significant decline in copper theft losses (as much as 45
per cent). 50 Eskom has also embarked on community engagement campaigns to address
this issue. Eskom’s Network and Energy Crime Committee in collaboration with other
affected state-owned companies and the South African Police Service have collaborated
to combat conductor theft. 51
The National Energy Act 52 addresses, inter alia, security of energy supply. Section
17 empowers the Minister of Energy to direct any state-owned entity to acquire, monitor,
maintain and manage national strategic energy feedstock and carriers in accordance with
published security strategies and policies. These strategies and policies must include
details of the minimum level of energy carrier or energy feedstock for the production of
an energy carrier; the conditions under which the strategic energy feedstocks and carriers
may be built, and withdrawals that may be made from such feedstocks and carriers;
45 As of the date of the Regulatory Agreement, Sasol’s customer base only included one reseller.
46 Act 102 of 1980.
47 The minister in charge of the administration of the National Key Point Act, pursuant to Proc 1
in GN21 in GG 26164 of 26 March 2004.
48 South African Police Service, www.saps.gov.za/default.htm.
49 In 2011, Eskom Transmission suffered losses of 2.9 million rand due to conductor theft and
5.3 million rand due to theft of steel tower members (pylon theft), http://financialresults.
co.za/2011/eskom_ar2011/index.php at p. 171.
50 As compared with losses in the 2009/10 financial year; see the Eskom Annual Report 2011,
http://financialresults.co.za/2011/eskom_ar2011/index.php at p. 171.
51 This combined effort resulted in the recovery of materials valued at 4.7 million rand in 2011,
http://financialresults.co.za/2011/eskom_ar2011/index.php at p. 211.
52 Act 34 of 2008.
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the funding mechanism for such energy feedstock or carrier; and the obligations to be
imposed, on producers of energy feedstocks, to supply to the nominated state-owned
entity the requisite energy feedstock, in a manner prescribed by regulation.
IV
ENERGY MARKETS
i Development of energy markets
Currently no organised markets for electricity or gas trading exist in South Africa. As
previously mentioned, under the ISMO Bill the ISMO will act as the sole market operator
in a single buyer market where it will aggregate all commercial generation purchases
and wholesale electricity sales to distributors. Electricity purchases by the ISMO will
be, at least over the short to medium term, subject to long-term take-or-pay power
purchase agreements with fixed tariffs, including existing power purchase agreements
concluded by Eskom as buyer which will be assigned to the ISMO by regulation. Under
the ISMO Bill, therefore, the ISMO will purchase electricity and then resell electricity to
distributors and large customers. The regulations and rules that will govern the ISMO’s
conduct as market operator have yet to be developed and it is therefore unclear at this
time when (or even if) South Africa will develop electricity markets to facilitate direct
sales among generators, traders and end-use customers.
ii Contracts for sale of energy
Electricity
Historically bilateral electricity purchases have not been precluded by law. Given the low
cost of electricity and high level of security of supply maintained by Eskom, 53 however,
South Africa did not offer any real opportunities for competing generators to engage in
the supply of electricity on a sustainable commercial basis.
By January 2008, South Africa’s reserve margin plummeted to 5 per cent.
Although by 2011, its reserve margin had increased to 14.9 per cent, it is generally
considered that the reserve margin will be under severe negative pressure over the next
five years given extended delays in the construction programmes for new Eskom baseload
generators, extended maintenance outages arising from the deferral of routine
maintenance on existing generators and increased demand. From April 2008 to March
2011 average wholesale electricity tariffs more than doubled (to 52 South African cents
per kWh) at an average annual escalation of about 23 per cent. According to information
presented in parliament, Eskom has assumed annual increases of 25 per cent for the
period April 2012 to March 2015 and increases of 6 per cent thereafter. Consequently,
many energy-intensive users, particularly in the minerals sector, have announced plans for
the procurement of IPP capacity under bilateral electricity sale and purchase agreements.
Recent proposed amendments to the electricity regulatory framework have
brought a measure of uncertainty as to the potential for the development of bilateral
energy markets operating outside the regulated single buyer market. As previously
53 Over the 1970s to 2007 South Africa enjoyed high reserve margins, generally in excess of 15
per cent.
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mentioned, current national government policy specifically favours the ‘managed
liberalisation’ of the electricity supply market to provide for the staged introduction of
IPPs within a single buyer market.
Proposed amendments to the ERA contained in the ERA Amendment Bill suggest
that the widespread commercial development of any new generation capacity outside
the regulated single buyer market is unlikely. Pursuant to these proposed amendments,
IPPs will need to obtain the approval of the Minister of Energy for the construction and
operation of commercial generation facilities (regardless of whether or not such generation
requires wheeling services from the transmission or distribution service providers). 54
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
The White Paper on Renewable Energy, 55 issued in 2003 by the then Department of
Minerals and Energy, set a target of 10,000GWh of energy to be produced from renewable
energy sources by 2013, mainly from biomass, wind, solar and small-scale hydro.
The IRP 2010–2030 allocates 42 per cent of South Africa’s total anticipated new
electricity generation capacity (17.8GW) to renewable energy technologies by 2030.
This will comprise 9 per cent of South Africa’s total electricity generation capacity by
2030. This 17.8GW is predominantly taken up by onshore wind technology (8.4GW)
and solar photovoltaic technology (8.4GW).
On 3 August 2011, the Department of Energy issued the procurement
documentation for the Department of Energy’s RE-IPP Procurement Programme.
This programme provisionally allocates the required 3.625GW as follows: 1,850MW
for onshore wind; 200MW for CSP; 1,450MW for solar photovoltaic; 12.5MW for
biomass; 12.5MW for biogas; 25MW for landfill gas; and 75MW for small hydro. The
programme allows for the revision of these allocations under certain circumstances and
is structured for up to five distinct bidding phases based on the rate of subscription.
The targeted commercial operation dates for the facilities to be procured under this
programme ranges from June 2014 to December 2016.
South Africa’s taxation legislation also incorporates the following mechanisms to
encourage the uptake of electricity generated from renewable energy sources:
a a carbon tax, referred to as an ‘environmental levy’ of 2.5 South African cents per
kWh, which is imposed on non-renewable energy generators; 56
b the cost of machinery and equipment used to produce bio-diesel or bio ethanol
or to generate electricity from wind, sunlight or gravitational water forces is
deductible from the tax-payer’s taxable income over a three-year period with
54 These amendments are proposed pursuant to the Electricity Regulation Second Amendment
Bill (GN905 in GG 34870 of 19 December 2011).
55 White Paper on Renewable Energy (Pretoria: Department of Minerals and Energy, November
2003).
56 This is scheduled to increase from 1 July 2012 to 3.5 South African cents per kWh (see Tax
Proposals: Budget 2012, www.sars.gov.za/home.asp?pid=75305 at page 11).
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c
50 per cent of the cost being deductible in the year in which the equipment is
brought into use, 30 per cent in year two and 20 per cent in year three; 57 and
to incentivise the uptake of Clean Development Mechanism projects in South
Africa, the proceeds received on the disposal of the carbon credits derived from
qualifying projects (commonly referred to as CERs) will be exempt from normal
tax and capital gains tax. 58
In addition, as a part of its response to climate change, the government intends to
introduce a carbon emissions tax. A carbon tax of 120 rand per ton of carbon dioxide (or
carbon dioxide equivalent) above a specified threshold is proposed to take effect during the
2013/14 financial year, with annual increases of 10 per cent until 2019/20. 59
ii Energy efficiency and conservation
Eskom’s integrated demand management division (‘Eskom IDMD’) is responsible
for implementing measures to encourage electricity load reduction through energyefficiency
programmes. These energy efficiency programmes include the widespread
implementation of compact fluorescent lamps in the residential areas, the rollout of
which commenced in December 2003. As of 2011, over 47 million bulbs had been
installed countrywide, realising demand savings of 1,958MW. Moreover, an exchange
programme swapped about 8 million compact fluorescent bulbs with incandescent bulbs
at exchange points in high public traffic areas. 60
Eskom IDMD commenced a solar water heating programme in 2010 under
which a capital rebate is offered to residential customers to replace electric water geysers
with solar water heating systems. 61 Eskom also issues daily power alerts over the national
broadcasting services to drive down household load reductions during peak usage times.
It is estimated that during 2011 average demand savings of 174MW were attained as a
result of these alerts. 62
Eskom has also initiated a demand market participation programme that allows
industrial customers with flexible load to contract with Eskom to reduce their load on a
year-ahead or day-ahead basis. Under this programme, Eskom is entitled, during periods
of supply constraints, to instruct customers to reduce their loads. 63
The National Energy Act addresses energy efficiency, which it defines as the
economical and efficient production and utilisation of an energy carrier or resource. This
Act empowers the Minister to prescribe minimum levels of energy efficiency for each
sector of the economy and energy conservation measures (such as energy consumption
57 Section 12B of the Income Tax Act 58 of 1962.
58 Section 12K of the Income Tax Act 58 of 1962.
59 Tax Proposal: Budget 2012, www.sars.gov.za/home.asp?pid=75305 at pp. 8–11.
60 Eskom Annual Report 2011, www.eskom.co.za/c/84/annual-report/ at p. 192.
61 Id.
62 Id.
63 Id.
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caps) to be used during any energy shortage including penalties for non-compliance with
those measures.
iii Technological developments
The South African National Energy Development Institute (‘SANERI’) is responsible for
energy research and development and devising measures for improving energy efficiency.
It was established in October 2004 64 by the then Minister of Minerals and Energy, as a
subsidiary of CEF (Pty) Ltd, the state energy company in South Africa. The Department
of Science and Technology (DST), together with the Department of Energy, are joint
custodians of SANERI and assist in providing political and strategic focus for the company.
Eskom has started to test hybrid smartgrid models to support its legacy time
multiplexing management system and an internet protocol packet communication
system to improve demand-side management, automatic generation control,
combustion efficiency of its thermal generation fleet and reliability of variable renewable
energy generators. 65 The initial aim of the testing is to establish the compatibility of the
information and communication technology (‘ICT’) architecture used in these models
with Eskom’s existing ICT systems; however, the business case for the full rollout of
the smartgrid migration still has to be developed. Eskom has implemented smartgrid
technology into parts of its 400,000-kilometre distribution network including the
rollout of fibreoptic cabling to most of its larger distribution substations and the use of
general packet radio services at its remote distribution substations.
VI
THE YEAR IN REVIEW
Key developments in the South African energy industry have been focused on the
electricity sector.
As mentioned in Section I, supra, the electricity legislative framework is in a state
of flux and significant reforms are underway to restructure the sector. These proposed
legislative reforms are contained in the ERA Amendment Bill, NERSA Amendment Bill
and the ISMO Bill. The principle features of these reforms are directed at:
a
b
c
d
e
the vertical unbundling of transmission;
the establishment of the ISMO, a 100 per cent state-owned company whose
representative shareholder will be the Minister of Energy, to take over Eskom’s
transmission business, including system operation and dispatch;
the routing of wholesale electricity supply through the ISMO;
the centralised control, by way of regulations to be made by the Minister of Energy,
over the determination of the make-up of the load customer base of the ISMO;
the managed liberalisation, in the discretion of the Minister of Energy, of
the electricity generation by way of the staggered introduction of IPPs for
64 Pursuant to the National Energy Act 34 of 2008.
65 Schalk Burger, ‘South Africa Hopes for Incremental Smart Grid Migration’, Engineering News
(30 March 2012), www.engineeringnews.co.za/article/business-needs-crucial-for-eskomsmart-grid-migration-2012-03-30.
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South Africa
f
g
h
i
participation within the ISMO-controlled single buyer market or regulated single
buyer market;
the centralised control, by way of the requirement for the prior approval of the
Minister of Energy, over the development of any commercial generation capacity
for participation outside the regulated single buyer market and resulting potential
‘chilling effect’ on bilateral supply arrangements;
the restructuring of NERSA from a nine-member board structure to a structure
comprising one Commissioner supported by three Deputy Commissioners, each
responsible for electricity, piped gas and petroleum pipelines;
the establishment of an Appeals Board to hear appeals from the decisions of
NERSA in respect of licensing and registration matters; and
the effective transfer of certain NERSA powers to the Minister of Energy,
including most notably the power to regulate the operation, use and maintenance
of transmission and distribution power systems.
Key anticipated events for the year ending December 2012 are the close out of the
Department of Energy’s procurement programme for IPP Peaking Power Generation in
South Africa (this comprises two diesel-fired open-cycle gas turbines for peak load power
generation totalling approximately 1GW) and the close out of phases one and two of the
Department of Energy’s RE-IPP Procurement Programme. In addition, it is anticipated
that the Department of Energy will launch at least two additional IPP procurement
programmes, one for small-scale renewable energy generators (between 1GW and 5GW)
and another for coal-fired base load generation capacity in the second half of 2012.
VII
CONCLUSIONS and OUTLOOK
South Africa’s abundant energy resources – and in particular fossil fuels such as coal, gas
and liquid fuels – continue to play a central role in the industrial and social development
of the country, with government policy moving towards encouraging a significant uptake
of renewable fuel sources. Although the regulatory framework is in place to encourage
private party participation in the upstream and downstream energy sectors, the state
currently plays a dominant role in the case of the electricity sector and is set to continue
to control market access through its policy preference for managed liberalisation of the
electricity sector. It remains to be seen whether proposed amendments to the energy
regulatory framework, and in particular the proposed amendments to the electricity
supply industry, will facilitate other key policy objectives for improved efficiencies in
energy supply and security of supply.
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Chapter 21
Spain
Antonio Morales 1
I
OVERVIEW
The energy sector is highly regulated (being a key sector), its strategic and technical
importance requiring a strong regulatory framework to ensure a constant supply at the
lowest possible cost and respecting environmental requirements.
This regulation has undergone significant change in recent years, mainly imposed
by European legislation, with introduction of market directives for the internal electricity
market in 1996 and 2009 (2009/72 of 13 July) and for the gas market in 1998 and 2009
(2009/72 of 13 July).
II
REGULATION
i The regulators
The framework for power distribution between the state and the autonomous regions
is directly established in Articles 149(1)(22) and (25) of the Spanish Constitution. The
former reserves the ‘authorisation of electrical installations when their use affects another
region or the transport of energy out of its territorial scope’ to the state’s exclusive
jurisdiction. The latter provides that the state has the jurisdiction over establishing the
basis of the energy regime. According to this framework, facilities within each region are
also authorised, and the legal bases of the energy sector develop.
The state’s wide jurisdiction in this area is reflected in the basic state legislation,
which establishes the sector’s regulatory framework: the Electrical Sector Law 54/1997
and the Hydrocarbon Law 34/1998. Since these two laws are very comprehensive and
wide-ranging, there is little space in practice for the autonomous regions to regulate.
1 Antonio Morales is a partner at Latham & Watkins LLP.
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The National Energy Commission (‘the CNE’) is the energy markets regulator.
Law 34/1998 establishes the CNE as the ‘performance regulator of energy systems,
being designed to ensure effective competition in the same as well as the objectivity and
transparency of its operation, beneficial to all consumers and those who operate these
systems’.
ii Regulated activities
Royal Decree 1955/2000 states that construction, expansion, modification and operation
of production facilities, transportation and distribution requires certain permissions.
An administrative authorisation is needed for the draft technical installation
document that is processed in conjunction with the environmental study. An application
is filed with the Directorate-General for Energy Policy and Mining, which is then
forwarded with the required documentation to the Ministry of Industry, which makes
the decision. If the resolution is positive it will indicate the time in which the application
must be submitted for project implementation approval, which – once approved – allows
the owner to construct or establish the installation. The application must be submitted
with the industry and energy sub-office where the facility is located. A resolution must
be arrived at within three months by the Directorate-General for Energy Policy and
Mining, specifying a deadline for the construction of the facility.
Once a project is duly implemented, an operating authorisation allows energy to
be transmitted to the facilities for commercial exploitation. The application for operating
must be submitted to the industry and energy sub-office and should be accompanied by
the final certificate of work.
Some autonomous regions have specific regulations for electrical installations;
they follow basically the same administrative procedure as established by the foregoing
state regulations.
iii Ownership and market access restrictions
Electricity network operation (transmission and distribution) is subject to significant
economies of scale, which gives them an element of natural monopoly, as it is inefficient
to introduce competition into these activities. Law 54/1997 establishes an obligation
to separate legal and accounting matters within regulated electric utilities (transmission
and distribution), which are provided under a financial regime. Deregulated activities
(generation and supply) are carried out by operators in free competition, their
remuneration being governed by the laws of supply and demand.
Directive 2009/72/CE and its subsequent incorporation into Spanish law go into
greater detail on this aspect and imposes an obligation on vertically integrated groups
to functionally separate their activities to ensure the autonomy of management and
decisions of those responsible for the transmission and distribution networks. In addition,
it purports to preserve the confidentiality of commercially sensitive information available
to those responsible so as not to compromise competition in deregulated activities.
Law 54/1997 and subsequent legislative developments established and defined
the role of different participants in the electricity sector:
a Power producers are individuals or legal entities that have the function of
generating electricity, as well as building, operating and maintaining generating
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Spain
b
c
d
e
f
g
plants. Depending on the generation technology used, producers are divided into
ordinary producers and regime producers.
Electricity transporters are companies that have the function of transporting
electricity and construction, maintenance and transportation transformer
facilities.
Distributors are those companies that have the function of distributing power,
and build, maintain and operate distribution facilities designed to establish energy
consumption points.
Sellers are legal persons who, by accessing transmission or distribution, have the
function of selling electricity to consumers. Among them are ‘last resort sellers’,
appointed by the regulator, which are functionally and legally separate from other
companies operating in the sector, which are responsible for providing energy to
consumers benefiting from the ‘tariff of last resort’ set by the government.
Consumers are individuals or corporations who buy energy for their own
consumption. The consumer who purchases energy directly in the production
market is referred to as a ‘direct consumer to market’.
The market operator (OMEL) is the company that assumes the management of
the bids for and sale of electricity in the daily power market in exchange for a
regulated fixed fee.
The system operator (Red Electrica of Spain) is the company whose main
function is to perform activities associated with the technical operation of the
electricity system, ensuring continuity and security of electricity supply and
proper coordination of production and transportation systems.
iv Transfers of control and assignments
Royal Decree 1955/2000 also establishes the authorisation for the transfer of installations.
The request for authorisation for facilities transfer needs to be sent to the Directorate-
General for Energy Policy and Mining, enclosing supporting documentation about the
applicants. A decision must be rendered by this department within three months (failure
to respond positively within three months means the application is deemed rejected),
prior to the report of the National Energy Commission. The applicant then has six
months to confirm the transfer.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
Energy (electricity or natural gas) is transported from the point where it is generated to
the point of consumption by large industrial consumers who are directly connected to
the transmission system and to the point of intersection with the distribution networks
(substations) through which power is carried to the remaining consumers.
The electricity transmission network is made up of lines, transformers and
other elements of voltage equal to or greater than 220kV. There are also international
interconnection facilities connecting Spain with other Spanish territories, which have a
voltage transport function lower than 220kV.
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Spain
Transport networks are developed when new investment is periodically approved
by the Ministry of Industry. The construction of network sections included in this
planning is regulated, and remuneration is calculated by the regulator in accordance with
the approved methodology in the regulations. Law 17/2007 established the single-carrier
model with Red Electrica of Spain as the owner of the entire transportation network. As
a system operator, it must comply with the relevant instructions by filing its investment
plans for the future years.
ii Transmission/transportation and distribution access
Power distribution brings the energy from the output of transport networks (electricity
or gas) to the final consumer. Electrical distribution facilities with voltage lines lower
than to 220kV, which are not considered part of the transport network, and all other
elements (communications, protection, control, etc.), need to be performing properly
and at a level of quality required by the regulations.
Prior to June 2009, distribution companies were also responsible for servicing
a regulated tariff supply to consumers. Since then, regulated supply has disappeared,
creating a ‘last resort supply’, which will be managed by ‘suppliers of last resort’, who
must supply electricity at a price no higher than that fixed by the government.
Distributors must build, maintain and operate power grids linking transport to
consumption centres. For the proper development of these functions, distributors have
the obligation to expand distribution facilities when needed to meet new demands for
electricity, at all times ensuring an adequate service quality level, and differentiating
by type of consumption and area. Furthermore, distributors are responsible for supply
measurement, applying consumer’s tolls or access fees.
Distributors are required to keep a points of supply database, always maintaining
confidentiality. They must send the required customer information to the Supplier
Exchange Office and provide reports to the transporter about their network incidence
and maintenance plans to ensure certainty of supply.
Finally, distribution companies must also provide information to clients, the
Ministry of Industry, Tourism and Trade, autonomous communities, Office for the
Change of Supplier and the system operator; they must also submit their investments
plans annually. Distribution companies, by the exercise of their activities, are entitled to
payment by the administration.
Notwithstanding the foregoing, prior to the approval of Royal Decree 222/2008,
laying down the emoluments of electricity distribution activity, electricity distributors
with fewer than 100,000 customers were covered by a special regulation (established
in Transitional Provision 11 of Law 54/1997) with a different financial and regulatory
regime to other distributors. Approval of Royal Decree 222/2008 meant that all
distribution companies would be subject to the same remuneration and policy, therefore
removing the previous size differentiation.
iii Rates
Remuneration for transportation is administratively established in response to investment
costs, operation and maintenance, and network management, according to a calculation
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model defined by the regulator by Royal Decree and in accordance with provisions
established in Law 54/1997.
This remuneration methodology aims to cover all costs of transportation
providing (including capital invested remuneration) and in turn encouraging effective
management. It is calculated every year as the sum of the following individual parts
linked to: the current value of investments, recovery of operation and maintenance costs,
and incentives for the availability and efficiency of facilities.
The fixed value of assets is calculated on the basis of reference unit costs approved
by the regulator. Annual remuneration of capital invested in these assets is calculated as
the sum of annual depreciation (value of assets divided by useful life) plus a return of
invested and recovered capital.
iv Security and technology restrictions
Security in relation to transportation facilities of electrical energy is relevant from the
perspectives of both industrial safety and security of supply.
Industrial safety is dealt with by Law 21/1996 of 16 July and Law 54/1997,
understood as safety aimed at risks prevention and control, as well as protection against
accidents and disasters capable of causing harm to the population or damage to flora,
fauna, property or the environment. Security of supply is dealt with under the electric
sector regulations. Law 54/1997 states in this regard that ‘few basic rules are established
techniques and needed to ensure the reliability of electricity supply and installations of
transport network’.
IV
ENERGY MARKETS
i Development of energy markets
According to Law 54/1997, electricity production takes place in the electrical power
production market in a free competition regime. The electricity production market is
composed of all business transactions of purchase and sale of energy and other services
related to the supply of electricity. It includes forward markets, a daily market, intraday
market, the resolution of technical constraints of the system, ancillary services, and the
management of deviations.
The Spanish electricity market has historically competitive prices for end users
compared with other European markets. The Iberian Electricity Market was started in
2007, and the results of this integration into the market have been obvious: while in the
second half of 2007 the average price differential between the Portuguese and Spanish
electricity systems was €10 per MWh, this difference fell to €0.3 per MWh by 2010,
with identical rates on both sides of the border for a majority of the time.
The operation of the wholesale market at any given time is determined by the
mix of generation structure, import capacity, the imperfect meshing of the network, the
inelasticity of demand and the system reserve margin. The market design rules can make
this operation more or less efficient, but cannot make up for significant deviations in
these factors.
From the opening to competition of the market generation in January 1998
until until 2005, almost all of the transactions in wholesale energy were carried out in
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the pool. Forward markets and bilateral contracts have been developed gradually with
the evolution of the regulations. Thus, in recent years, the energy involved in the daily
market run by OMIE (the Iberian Electricity Market Operator) has ranged between 45
and 55 per cent of demand, with the remainder opting for bilateral transactions.
Despite the reduction in the quantities traded in the daily market, its price still
represents the main visible energy price reference and the underlying settlement of
bilateral contracts, the over-the-counter (‘OTC’) market and forward markets organised
by OMIP (Iberian Market Operator Portugal).
In this context the significant increase in OTC negotiations on the financial
market should also be noted. The volume of energy traded in this market went from 6
per cent of domestic demand in 2007 to 10 per cent in 2010.
The low prices in the Spanish wholesale market compared with their European
counterparts have reflected the influence of generation technology’s price takers. As an
illustrative example, in December 2009 to March 2010 period the market price showed
a very substantial fall even below fuel price, reaching an average of €19.6 per MWh in
March 2010, reflecting, inter alia, prices of €0 per MWh for almost 300 hours. One of
the main causes of this was a 1.91 per cent reduction in demand, along with growth in
wind production coinciding with intense rainfall.
ii Energy market rules and regulation
Since 1998 the Spanish electricity sector has undergone a major transformation as a
result of regulation changes resulting from the adoption of Directive 96/92/EC, the
main objective of which was to create an internal market for electricity in the EU by
liberalising electricity generation and sale.
The electricity markets are regulated by:
a a market operator, responsible for the preparation of the daily operation of the
system, matching offers and demands, supervised by a committee of representatives
of producers, distributors, traders and qualified consumers;
b a system operator, ensuring continuity and security of supply (Red Electrica of
Spain);
c the Electricity System Commission, which protects consumer interests and
ensures the transparency of the whole system; the Industry and Energy Ministry
must supervise the correct operation of production activities and consumption of
electricity;
d autonomous communities, which also have direct responsibilities in regulating
their electrical systems; and
e the European Union, which establishes the general framework of the electrical
system in all countries of the Union through directives and legal regulations.
Royal Decree 949/2001, which regulates third-party access to gas infrastructure and
establishes an integrated economic systmem of the natural gas for regulated activities
paid under rates, tolls, and regulated fees, also sets out the basic criteria for remuneration
of regulated activities, setting tariffs and fees to be paid by individuals for the use of gas
installations.
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iii
Contracts for sale of energy
Spain
Participants on the energy market may freely agree the terms of contracts for the sale of
electricity to subscribe, subject to the terms and minimum content under Law 54/1997
and its implementing regulations.
Electricity traded through daily and intraday markets is remunerated on the
basis of the prices resulting from the balance between supply and demand of electricity
offered. Electricity traded through bilateral contracts or the physical or term market is
remunerated on the basis of the price of the firm contracted operations in those markets.
iv Market developments
Historically, the energy market has functioned properly, but in recent years a technologydriven
influx of price takers has distorted its proper functioning. This has caused a
reduction in the wholesale market price, which, together with a reduction in the thermal
gap, is not sending the right economic signals to garner investment in new capacity.
This situation will only deteriorate in the future, as the progressive decarbonisation
production mix forecasts a greater presence of non-renewables, relegating thermal
technologies’ main role as backup power with only a residual role as contributor energy,
jeopardising the recovery of investment. Incentives for investment and the availability of
service, recently established in Order ITC/3127/2011, have not sent sufficient economic
signals to encourage investment in new backup power in the vicinity of 500 hours per
year, which highlights the need to revise that target.
In particular, a procedure to assist supply security was introduced in 2011 with
the aim of ensuring a level of domestic coal consumption according to the provisions
of the National Coal Plan (which justifies the operation of these plants for security of
supply and capacity for each state to give priority to indigenous sources for up to 15 per
cent of production). This regulatory change involves the generation of coal that is paid
(10 plants totalling 4,700MW) at a regulated price, while production in the process of
withdrawal of the production-demand balance (imported coal and combined cycle) does
not receive any compensation.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Special regime installations, which include renewable energy sources, are not subsidised
in the state budget. Instead, they are included in electricity rates, causing a ‘tariff deficit’;
however, not only do renewable energy premiums generate a tariff deficit, so do other
items such as regulated tariff billing. In fact, the special regime premiums cause only
a third of the tariff deficit. In this context, however, the purpose of Royal Decree-Law
1/2012 is to limit the impact of renewable premiums in the tariff deficit, thus reducing
costs.
Royal Decree 6/2009, dated 30 April, had previously attempted to limit the
increase of the aforementioned general tariff deficit, however, it was not sufficient, given
that only a year later further steps needed to be taken by the government: a new Royal
Decree Law 14/2010 was passed, for the same purpose.
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While the government is planning a reform in the electricity industry to avoid
tariff deficits, it has decided to suspend financial incentives to build new energy projects
on a temporary basis. This situation has been brought about both by the global economic
crisis and by financial difficulties being experienced by the electricity industry. Measures
taken to date have not been effective in reducing this deficit, thereby making overall
sector development more difficult, and hindering the continuation of policies promoting
electric power from renewable energy sources. Royal Decree-Law 1/2012 will be part of
a large group of other regulatory measures that will probably need to be passed in the
future to change and improve the fortunes of the energy sector.
The government is maintaining its commitment towards keeping renewable
energy as an essential part of Spain’s energy mix. In 2011, 33 per cent of electricity
demand was derived from renewable installed power, making Spain a leader in this type
of energy; however, the current payment system is not sustainable, given the reduction in
demand caused by the financial crisis. Until the system is reformed, the current payment
system has been suspended.
ii Energy efficiency and conservation
Objectives and actions on energy efficiency in Spain are part of the policy objectives
and progress set by the regions’ institutions. Also, in addition to the objectives approved
in the European Council in spring 2007 of reducing greenhouse gas emissions and
increasing renewable energy, a target was included of improving energy efficiency by
20 per cent in 2020 in the EU compared with the baseline scenario (the target block is
commonly called 20-20-20 targets). Unlike the target for 20 per cent renewables and 20
per cent reduction of CO 2
emissions, the efficiency target is not binding and has been
distributed by Member States.
In line with European objectives, the only public reference in a Spanish context
has been the 20 per cent target of improving energy efficiency in the government’s
‘Strategy for a Sustainable Economy’ in December 2009, which includes a target 20 per
cent reduction in energy usage by 2020 compared with the current scenario.
In at national level, the main energy efficiency measures are based on the Spanish
Energy Efficiency Strategy (E4) for the period 2004–2012, which has developed in
several plans: Plan of Action 2005–2007, Plan of Action 2008–2012 and Plan of Action
2011–2020.
The 2008–2012 Action Plan includes a significant number of structured activities
and strategic sectors. The measures carried out are divided into the following categories:
a Legislative actions, in general far-reaching, and representing a complex set of
recommendations, regulations, rules of functioning, constraints, and generally
binding rules.
b Incentive measures for carrying out audits and analysis of consumption of the
technologies used, and promoting investment in equipment to increase energy
efficiency.
c Training in good practices, knowledge of available technology, advances and new
techniques of management demand, consumption and, in general, the correct use
of energy.
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Alongside this plan, some of the key energy efficiency measures stated in the Spanish
Action Plan 2011–2020 include those in the transportation, building, utilities and
cogeneration sectors.
iii Technological developments
Royal Decree 1565/2010, dated 19 November, which modifies some aspects of the
special energy production regime in order to promote innovative investment, stated that
the Ministry of Industry could grant additional compensation for solar thermoelectric
projects installations with a high level of innovation by means of a tender. Through a
resolution dated 24 June 2011 of the State Secretary for Energy, the tender was granted
to Termosolar Alcazar SL.
VI
THE YEAR IN REVIEW
The Spanish government temporarily suspended pre-allocation registration as well as
abolishing financial incentives for new energy production projects using cogeneration,
renewable energy sources and waste, as a consequence of the complex economic and
financial situation that Spain is currently undergoing. The intention is to temporarily
halt a reward system that involves a substantial cost for the electricity system, which has
caused the tariff deficit to continually increase. This measure does not jeopardise supply,
nor the renewable energy sources targets set by the European Union.
It also passed Royal Decree-Law 13/2012, dated 30 March, by which the
directives on internal markets for electricity and gas field and electronic communications
were incorporated, adopting measures to correct deviations between electricity and gas
costs and revenues.
VII
CONCLUSIONS and OUTLOOK
Spain heavily depends on foreign energy and needs all available sources. Its system has
been in constant state of revision and has created legal uncertainty for international
investors, who demand safe, predictable and transparent markets. The main objectives
for the government in a short term are to shore up its markets for this purpose, but it is
also important to definitively outline the energy mix that is wanted for the next 20 years;
once defined, this plan should be stuck to for that period of time.
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Chapter 22
Sweden
Hans Andréasson, Martin Gynnerstedt and Malin Håkansson 1
I
OVERVIEW
Swedish energy policy shares a common basis with energy policy developed at the EU
level and aims at ecological sustainability, fair competition and security of supply. The
policy strives to create conditions for efficient, sustainable energy consumption and a
cost-efficient energy supply involving a reduced negative impact on people’s health, the
environment and the climate, and enabling the transition to an ecologically sustainable
society.
Approximately half of the electricity consumed in Sweden comes from renewable
energy sources (e.g., hydropower, biofuels and wind power, hydropower being the main
source in this category, amounting to over 40 per cent), whereas around 40 per cent is
generated by nuclear power.
Electric power and natural gas are bought and sold on an open and free competitive
market and no authorisation is required for the sale of electric power or natural gas to
customers.
Although the Swedish electricity and natural gas markets have been deregulated,
they still are characterised by high market concentration and a limited number of large
operators.
Sweden is part of an integrated Nordic power market. In recent years, there has
been an increase in the amount of electricity exchanged between Sweden and other
countries, including the other Nordic countries. This is a trend that is expected to
continue.
1 Hans Andréasson is a partner, and Martin Gynnerstedt and Malin Håkansson are senior
associates at Mannheimer Swartling.
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II
REGULATION
i
The regulators
The main regulatory body for the Swedish energy markets is the Swedish Energy Markets
Inspectorate (‘the Inspectorate’), an authority under the Ministry of Enterprise, Energy
and Communications. It supervises the Swedish electricity, natural gas and district
heating markets. One of the main responsibilities of the Inspectorate is to improve the
functioning and efficiency of these markets. The Swedish parliament and the government
decide on the assignments and budget of the Inspectorate.
Svenska Kraftnät, which owns and operates the national grid, is a state-owned
public utility, responsible for transmitting electricity from the major power stations
to regional electrical grids via the national grids. Svenska Kraftnät is also the system
operator under the Electricity Act, 2 which means that it has overall responsibility for
electrical plants working together in an operationally reliable way so that the balance
between the production and consumption of electricity is maintained throughout the
country. Svenska Kraftnät is also responsible for the Swedish natural gas system and the
coordination of dam safety.
The Swedish Radiation Safety Authority is an authority under the Ministry of the
Environment with national responsibility within the areas of nuclear safety, radiation
protection and nuclear non-proliferation, and it is tasked with supervising the parties or
licensees conducting the activities that may involve radiation in a safe manner.
Central statutes for the energy markets are the Electricity and the Natural Gas
Acts, 3 the District Heating Act 4 and, for nuclear energy, the Nuclear Activities Act 5 and
the Radiation Protection Act. 6 Sweden has implemented EU’s 3rd Energy Package,
including the Directive 2009/72/EC concerning electricity and the Directive 2009/73/
EC concerning natural gas, mainly as part of the Electricity Act and the Natural Gas
Act. 7 The relevant regulations, which are part of the 3rd Energy Package, directly apply
to Sweden.
ii Regulated activities
The establishment and construction of energy production facilities may involve different
types of land or water use and therefore requires permits and regulatory approvals under
traditional property law including building permits and other issues under the Planning
and Building Act, and environmental permits under the Environmental Code. These
2 SFS 1997:857.
3 SFS 2005:403.
4 SFS 2008:263.
5 SFS 1984:3.
6 SFS 1988:220.
7 Directive 2009/72/EC of the European Parliament and the Council of 13 July 2009 concerning
common rules for the internal market in electricity and repealing Directive 2003/54/EC and
Directive 2009/73/EC of the European Parliament and the Council of 13 July 2009 concerning
common rules for the internal market in natural gas and repealing Directive 2003/55/EC.
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application processes may be both lengthy and complex in nature and require that
environmental investigations and impact analyses are carried out in order to receive the
necessary approvals. Additionally, in most cases a permit is also needed for the operation
of an energy facility.
The purchase and sale of electricity in Sweden takes place on a deregulated market
with competition between the parties involved.
A high-voltage electrical power line may not, with a few exceptions, be built
(or operated) without a permit – a network concession – covering either a specific line
or an area. A network concession may be granted provided that the line is considered
appropriate from a general point of view and that it meets certain other requirements,
including specific environmental qualifications. Network concessions will be granted
only to legal persons that are suitable to conduct network operations. As a rule, a network
concession for interconnectors may only be granted to a ‘stamnätsföretag’, a legal entity
that holds network concessions for the national grid (currently only Svenska Kraftnät) or
to legal entities that are controlled by a stamnätsföretag.
The rule regarding network concessions for the establishment of a high-voltage
power line also applies (more or less) in the natural gas segment with regards to the
establishment of high-pressure pipelines.
iii Ownership and market access restrictions
Foreign investors can participate on equal terms with Swedish investors on the energy
market. There are, however, some ownership and market access restrictions, for example,
that the establishment of a high-voltage electrical power line or a high-pressure pipeline
requires a network concession (see above).
The implementation of EU’s 3rd Energy Package has also resulted in some new
ownership restrictions in the electricity and natural gas markets (see Section III.i, infra).
iv Transfers of control and assignments
An electric network or a natural gas concession may not be transferred without the
permission of the Inspectorate. Such permission will only be granted to a party considered
suitable to engage in network operations from a public perspective.
Mergers and acquisitions and joint ventures in the energy market may also require
approvals from the Swedish Competition Authority. The thresholds of the energy industry,
regardless of the segment, are the same as those that apply under the Competition Act. 8
A concentration must be notified to the Competition Authority if:
a the combined aggregate turnover in Sweden of all the undertakings concerned
during the preceding financial year exceeds 1 billion kronor; and
b at least two of the undertakings concerned each had a turnover in Sweden during
the preceding financial year exceeding 200 million kronor.
8 SFS 2008:579.
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Transactions leading to a significant impediment to effective competition,
in particular through the creation or strengthening of a dominant position, are not
permitted.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
One of the main objectives of the Electricity Act with respect to vertically integrated
companies is to create a clear separation between the transmission or distribution
of electricity (i.e., network operations) on the one hand, and activities concerning
production or generation of, or trade in, electricity, on the other hand. Legal entities
carrying out network operations (i.e., the holders of the network concession) are not
allowed to engage in generation or trade in electricity: structural unbundling is required
for all legal entities conducting network operations. Notwithstanding this restriction,
such legal entities may generate electricity if such generation is exclusively intended to
compensate for losses in the network, or if it is performed by mobile reserve plants
intended for occasional use during power outages. Furthermore, legal entities conducting
network operations whose network system, together with the total network system of
the group of companies of which they are a part, have at least 100,000 electricity users,
must also be functionally unbundled. As a result, the Electricity Act forbids legal entities
that conduct generation from having the same board members, managing directors or
authorised signatories as undertakings that trade in electricity, or vice versa. Legal entities
must also have necessary assets to be able to make decisions independent of any group of
companies to which they belong.
With Directive 2009/72/EC and Directive 2009/73/EC, new rules have been
introduced on unbundling for transmission system operators (‘TSOs’). The unbundling
regime provides for three models: the ownership unbundling model (TSO model),
the independent system operator (ISO) model, and the independent transmission
operator (ITO) model. The models are intended to, inter alia, remove the incentive for
vertically integrated undertakings to discriminate against competitors as regards access
to the network, and commercially relevant information and investments in the network.
Sweden has chosen the TSO model for both the electricity market and the gas market.
It may be noted that Swedish electricity legislation does not make a clear
separation of transmission and distribution, transmission systems and distribution
systems, or transmission system operators and distribution system operators. The
ownership unbundling requirements of the TSO model applies to one legal entity only
in Sweden: Svenska Kraftnät, the owner and operator of the national grid. In view of the
Directive’s definition of ‘transmission system operator’, the national grid appears to be
the only network system that meets the criteria of being a transmission system.
The Natural Gas Act includes a somewhat different regulation than the Electricity
Act. The Swedish natural gas network system extends from south of Malmo in southwest
Sweden and along the west coast to north of Gothenburg. Due to the limited
network system extension and low number of participants – currently only five
companies sell natural gas – the Swedish gas market is rather limited, which appears to
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be one of the reasons for the different regulation in the Natural Gas Act as compared
with the regulation in the Electricity Act (although the EU legislation in many respects
is the same for electricity as well as for natural gas). All Swedish high-pressure pipelines
are currently owned by a privately owned company, Swedegas AB. Accordingly, the
ownership unbundling requirements of the TSO model applies only to Swedegas AB.
Legal entities carrying out distribution of natural gas may not be also engaged in trade in
natural gas, but are not subject to any functional unbundling requirements.
ii Transmission or transportation and distribution access
As previously stated, the electricity legislation makes no clear separation between
transmission and distribution. The only network system which appears to meet the
definition of ‘transmission system’ of Directive 2009/72/EC is the national grid, which
is owned, administered and operated by Svenska Kraftnät. The ownership and operation
of the regional distribution systems are concentrated on three large business groups,
Vattenfall, E.ON and Fortum. Several of the local distribution networks are owned and
operated by local municipalities.
Since 2011, Swedegas AB has been the owner of all high-pressure pipelines in the
natural gas sector in Sweden.
The EU’s 3rd Energy Package has in reality had little – if any – impact on the
structure of the Swedish electricity and natural gas markets. This is due to there being
only a few players, only one company on each of the electricity and the natural gas
markets qualifying as a TSO, and the fact that the Swedish electricity market has already
been deregulated since 1996 and the natural gas market since 2005.
A holder of a network concession is required to connect, on reasonable terms and
conditions, an electrical installation to the grid, unless there are specific reasons not to
do so (e.g., insufficient grid capacity). Thus, generators may be connected to the national
grid or a regional or local network as agreed with the respective network owner. The
entire set of terms and conditions for the connection must be reasonable, including the
allocation of the connection costs. A network owner is, however, not normally expected
to make heavy investments to enable a connection. Disputes relating to the conditions
of the connection, including the tariffs charged by the concession holder, are settled
in the first instance by the Inspectorate, the supervising authority under the electricity
legislation.
A holder of a network concession is furthermore obliged to allow the transmission
and distribution of electricity through its power lines to any person or company on
reasonable terms and conditions with respect to tariffs, payment terms, contract terms,
termination, energy volume and effect (the regulations with respect to tariffs are further
described below). New rules are expected to be introduced in the Electricity Act during
2012 regarding the other conditions relating to the transmission and distribution, which
will place an obligation on the holder of the network concessions to have its terms and
conditions approved by the Inspectorate prior to imposing them on its customers.
The aforementioned principles apply in all material respects also to the gas market.
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iii Rates
The tariffs charged by network operators for the transmission or distribution of electricity
on the networks must be objective and non-discriminatory.
Through changes in the Electricity Act that entered into force on 1 January 2012,
Sweden has gone from a network tariff system where the tariffs were regulated on an ex
post basis to a system with an ex ante regulation. The ex post regulation involved that the
tariffs were set by the network operators without any prior approval of the Inspectorate,
who monitored the tariffs as they were applied and intervened only where the tariffs
were considered unreasonable. One of the purposes of changing to ex ante regulation is
to bring Swedish legislation in line with the EU Directives.
The Inspectorate will now determine, in advance, that the total revenues collected
by the network operator during the regulatory period – four years as a rule – do not
exceed a certain income cap. At the end of the regulatory period, the Inspectorate will
assess to what extent the network operator’s actual total revenue deviates from the income
cap. Any amounts in excess of the cap will reduce the income cap to be determined for
the subsequent regulatory period, whereas any amount whereby the total revenues are
below the income cap will increase such income cap. If the income cap is exceeded with
more than five per cent, the cap for the subsequent regulatory period will also be reduced
by an overcharge fine. The Inspectorate can, upon application by the network operator,
under certain circumstances revise the income cap during or after the regulatory period.
The first regulatory period for the new system began on 1 January 2012. The
income cap must cover reasonable costs for the operation of the network operations
during the regulatory period and provide a reasonable rate of return on the capital
expenditure required to operate the network; the quality of the network operations
must be taken into account. The network operators submitted their applications for
the income caps in early autumn 2011. Those eventually approved by the Inspectorate
were much lower than the income caps many of the network operators had applied for.
A number of network operators have therefore appealed the Inspectorate’s decisions to
the administrative court. Since the income cap regulation is new, the outcomes of the
appeal processes are of interest as they may form precedent for future application of the
regulation.
On the natural gas market, the tariffs for transmission of natural gas are still
regulated on an ex post basis. If the Inspectorate finds that the tariffs have been too high,
the network companies can be ordered to repay its customers.
In order to bring the Swedish natural gas legislation with respect to tariff regulation
in line with the tariff regulation on the electricity market, amendments to the Natural
Gas Act have been proposed and ex ante regulation of the tariffs is expected to enter into
force in 2013.
iv Security and technology restrictions
The Energy Agency is the administrative authority for the supply and use of energy
in Sweden and as such safeguards the maintenance of electricity and other energy in
both the short and long term. The Agency has developed a planning system for the
supply of electricity in case of shortage and it has been authorised by the government
to make decisions with respect to how the limitation or discontinuation of electricity
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supply may be planned. 9 Changes have been made in the Electricity Act to the effect that
disconnection in case of shortage will no longer be made ‘as fair as possible’, but in such
way that ‘critical infrastructure electricity users are prioritised’.
According to this structure, electricity users will maintain their supply in
accordance with their ranking on a list of prioritised critical infrastructure electricity
users. The principles and basis for the prioritisation is to divide users of electricity in
Sweden into eight groups, the first being users that, within hours of shortage, have
a large impact on people’s lives and health. The new system for prioritising – which
formally came into effect as of January 2012, but not yet in practice all over Sweden as
the transition is still ongoing – is designed on the assumption that disconnection can
be made on a local grid level, whereby existing electricity may be directed to prioritised
users, whereas other users are disconnected.
In the case of a future electricity shortage, Svenska Kraftnät, operator of the national
grid, may thus order the power supply companies to disconnect users in accordance with
plans prepared by the principle of ranking critical infrastructure electricity users. Users
of specific importance may include railways, larger airports and structures used by the
Swedish armed forces or for electronic communication.
IV
ENERGY MARKETS
i Development of energy markets
The deregulation of the electricity markets of the Nordic countries in the mid-1990s
was followed by an integration of the Nordic markets and the establishment of a Nordic
electricity exchange, the Oslo-based Nord Pool. Today, the trading in physical electricity
contracts is organised by Nord Pool Spot, which is owned jointly by the transmission
system operators of Norway (30 per cent), Sweden (30 per cent), Denmark (20 per cent)
and Finland (20 per cent), whereas the trading in financial (i.e., cash-settled) electricity
contracts is organised by NASDAQ OMX Commodities, a division of the NASDAQ
OMX group.
Nord Pool Spot offers day-ahead auctions (the Elspot market) and continuous
intraday trading (the Elbas market).
On the day-ahead market, which covers Denmark, Estonia, Finland, Norway
and Sweden, Nord Pool Spot participants enter into contracts for sale and purchase of
electricity for delivery hour-by-hour the next day. Bids and offers must be entered into
the trading system before noon on the day prior to delivery. Orders are made as singlehour
orders or as all-or-nothing block orders for delivery over several hours.
As soon as the deadline to submit orders has expired, all purchase orders and
sell orders are aggregated into two curves for each delivery hour: a demand curve and
a supply curve. The system price for each hour is determined by the intersection of the
demand and supply curves representing all bids and offers made in the Nord Pool Spot
area. In connection with the publishing of the prices for the next day, each participant
receives a report on how much electricity it has bought or sold for each hour of the next
9 Decree on Planning for Prioritising of Critical Infrastructure Electricity Users (SFS 2011:931).
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day. The net positions of the participants are also sent to the TSOs of the Nord Pool Spot
area, who use the information to calculate the balancing power for each participant.
The intraday market Elbas, which is available in the Nordic countries, Estonia and
Germany, serves as an adjustment market where members can trade contracts until one
hour before delivery. As more wind power – which by nature is unpredictable – enters
the transmission grid in northern Europe, intraday trading is increasingly becoming
more important.
As a complement to the market for physical contracts, NASDAQ OMX
Commodities organises trading and clearing in standardised cash-settled financial
electricity contracts. The contracts listed for trading include future, forward and option
contracts, and contracts for difference, of a duration of up to six years.
ii Energy market rules and regulation
Trading in energy contracts may be subject to general Swedish insider trading regulations, 10
which imposes certain restrictions on dealings in energy contracts if considered ‘financial
instruments’. 11 This will apply to, inter alia, financial electricity contracts traded on
NASDAQ OMX.
EU Regulation 1227/2011 on wholesale energy market integrity and transparency
(REMIT), which entered into force on 28 December 2011, is directly applicable in
Sweden and introduces insider-dealing restrictions specifically covering trading in
wholesale energy products. The Regulation involves a system of disclosure, registration
and enforcement to be overseen by the EU Agency for the Cooperation of Energy
Regulators (ACER) in cooperation with the national regulatory authorities. It applies to
transactions in wholesale energy products (electricity and gas only), both actual contracts
and derivatives. Among the obligations that are now in force are prohibitions of insider
trading and market manipulation, and obligations to publish inside information.
iii Contracts for sale of energy
In 2010, approximately 74 per cent of the consumption of electricity in the Nordic
countries was traded on Nord Pool Spot. Market participants may also sell power, as well
as natural gas, by entering into individual contracts.
There are no specific regulatory requirements that govern the contractual terms
for energy sales as long as the end-user is not a consumer. A company supplying
electricity, however, must conclude an agreement with Svenska Kraftnät, which operates
the national grid, for the balancing responsibility or have entered into an agreement
with another company for the balancing responsibility as a service. The aforementioned
principles apply in all material respects also to the gas market.
10 The Swedish Market Abuse Act (SFS 2005:377) implementing the EU Directive 2003/6/EC
on insider dealing and market manipulation.
11 ‘Financial instrument’, as defined under the Swedish Securities Market Act (SFS 2007:528)
implementing the EU Directive 2004/39/EC on markets in financial instruments.
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iv
Market developments
Sweden
Since 1 January 2012, Sweden and Norway have a joint electricity certificate market. The
aim for the two countries is to increase their production of electricity from renewable
energy sources by 26.4 TWh by 2020. A common market allows trading in both Swedish
and Norwegian certificates, and certificates to be received for renewable electricity
production in either country.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
A new climate and energy policy was adopted by the Swedish parliament in 2009. 12 It set
a target for the consumption of energy from renewable sources, which in 2020 should be
at least a 50 per cent share of the total energy consumption, as compared with the 20 per
cent target that applies at EU level.
Traditionally, the tax system has been the means of control to reach the energy and
climate policy goals in Sweden. In connection with the tax reform in 1990–91, Sweden
began the process of a ‘green tax exchange’. Under the green tax exchange scheme, energy
taxes have been increased and the revenues from those taxed used for other purposes, for
example, decreasing income tax. The idea is to put a price on the environment by, for
example, making pollution more expensive, thereby influencing people to make more
energy-smart choices. The main legal framework with respect to energy taxation is laid
down in the Act on Excise Duties on Energy, 13 which contains provisions on energy tax,
carbon dioxide tax, sulphur tax on fuels, and energy tax on electricity. 14
Nowadays, there is an increased interest in market-based instruments such as
emission trading rights and electricity certificates. The EU’s emission trading system
has been implemented in Sweden by the Act on Trade in Emission Rights 15 and the
Ordinance on Trade in Emissions Rights. 16,17 The Energy Agency is the National Registry
administrator for Sweden and the National Registry has been operational since the
beginning of 2005.
12 Government’s bill, prop. 2008/09:163.
13 SFS 1994:1776.
14 Directive 2003/96/EC restructuring the Community framework for the taxation of energy
products and electricity has been implemented into this Act.
15 SFS 2004:1199.
16 SFS 2004:1205.
17 Inter alia, Directive 2003/87/EC of the European Parliament and of the Council of 13
October 2003 establishing a scheme for greenhouse gas emission allowance trading within
the Community as well as the subsequent amendments to this Directive, including but not
limited to Directive 2004/101/EC amending Directive 2003/87/EC establishing a scheme for
greenhouse gas emission allowance trading within the Community, in respect of the Kyoto
Protocol’s project mechanisms.
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The Electricity Certificates Act entered into force in 2003. 18 The purpose of the
Act is to promote the production of electricity from renewable energy resources through
the use of the competitive mechanisms of the market. A market supply of electricity
certificates is created by the state issuing tradeable certificates to the producers for
every megawatt hour of electricity produced from renewable energy resources such as
wind power, small-scale hydropower, certain biofuels, solar power, geothermal power,
wave power and peat used in combined power and heating plant. A market demand
for certificates is created by imposing an obligation on electricity suppliers to purchase
and keep an annual stock of certificates corresponding to a certain proportion of the
electricity that they sell in the relevant year – a ‘quota obligation’. Should the electricity
supplier not keep the necessary amount of certificates, a fee will have to be paid. The
supplier’s cost of the electricity certificates are transferred to the energy customers as part
of the price of the electricity. As the costs of the electricity certificates are transferred
to the customers, the electricity prices for other than green electricity will rise, giving
customers an incentive to purchase green electricity. Electricity-intensive companies,
which are registered at the Energy Agency, are obliged to handle the quota obligation
themselves. Such companies are to some extent also exempt from the quota obligation
to avoid that the costs relating to the purchase of electricity certificates get too high and
thereby risk harming such companies’ competitiveness on the international market.
Also the Renewable Energy Directive 19 has been transposed into Swedish law
by, inter alia, the Act Concerning Sustainability Criteria for Biofuels and Bioliquids. 20
The Act includes specific requirements concerning sustainability criteria for biofuels
and bioliquids. These sustainability criteria have to be fulfilled in order to attain tax
exemptions for the relevant biofuels and bioliquids.
Other means of reaching the energy policy goals include various restrictions
as regards emissions, which are imposed on industries through the environmental
legislation, energy efficiency programmes (see Section V.ii, infra) and the support
through, inter alia, grants distributed by the Energy Agency to research and development
projects concerning supply, transformation, distribution and use of energy.
ii Energy efficiency and conservation
Various measures have been undertaken within the area of energy efficiency, mainly
aiming to improve the efficiency within the Swedish industries and the building sector.
The programme for energy efficiency, for example, is an economical means of control
aimed at energy-intensive Swedish industries. Such industries may apply to a five-year
programme where they undertake to work with energy issues on a structured basis and
to implement energy-efficiency measures. In return, these industries will be granted an
energy tax reduction.
18 The 2003 Act has now been replaced by the new Electricity Certificates Act (SFS 2011:1200).
19 Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on
the promotion of the use of energy from renewable sources and amending and subsequently
repealing Directives 2001/77/EC and 2003/30/EC.
20 SFS 2010:598.
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A number of measures have also been undertaken in the building sector to
promote energy efficiency. For example, there have been programmes involving
investment support for the installation of solar heating systems and the conversion of
heating systems. Another measure is the introduction of an obligation for all owners of
buildings to undertake energy assessments for their buildings.
iii Technological developments
The Energy Agency provides support to Swedish energy research and innovation
projects. For the next five years the Agency proposes to give priority to five areas: fossil
fuel-dependent vehicles, renewable electricity within the power system, energy efficiency
within the building sector, increased use of bioenergy and energy efficiency within
Swedish industry. Support is given by way of grants to, inter alia, basic research projects,
development of new energy technology, business development and innovations.
VI
THE YEAR IN REVIEW
On 14 April 2010, the EU Commission took a decision to the effect that Svenska
Kraftnät, which owns and operates the national grid, must alter the way in which it
manages transmission limitations in the Swedish electricity network. This decision was
a consequence of the fact that the model in use until then (when the whole of Sweden
was one single bidding area) was considered to discriminate against foreign customers.
As a result of this, Svenska Kraftnät divided Sweden into four bidding areas with
effect from 1 November 2011:
a Luleå - the north (surplus of generation)
b Sundsvall - the mid-north (surplus of generation)
c Stockholm - the mid-south (shortage of generation)
d Malmo - the south (shortage of generation)
This division illustrates that there are imbalances in the Swedish network system due to
shortage of feed-in power and that transmission limitations (bottlenecks) exist in the
grid. It also indicates where it is necessary to increase generation in the country in order
to decrease the need for long-distance electricity transmission.
VII
CONCLUSIONS and OUTLOOK
The Swedish energy market is a relatively small market dominated by few market players
and is heavily dependent on hydro and nuclear power. The Swedish government decided
in 1980 that a phase-out of nuclear energy should be completed by 2010. In 1997
energy policy allowed 10 reactors to operate longer than envisaged by the 1980 phaseout
policy. On 17 June 2010, the Swedish parliament adopted a decision allowing the
replacement of the existing reactors with new nuclear reactors, starting from 1 January
2011, although construction will only be at existing sites and to replace the present 10
units. The abolition of the act banning construction of new nuclear reactors in Sweden
was a part of the government’s climate programme to reduce greenhouse gases. Another
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aspect that most certainly contributed to the government’s policy change was a shift in
public opinion in favour of continuing nuclear power in Sweden.
After the earthquake and tsunami in Japan 11 March 2011 and the following
Fukushima nuclear accident, the interest in replacing existing nuclear reactors seems
to be low among nuclear companies. It must, however, be kept in mind that the 10
existing nuclear reactors in Sweden were put into operation between 1972 and 1985,
which makes the reactors quite old in an international context. Due to Sweden’s current
dependency on nuclear power, it is likely that in the near future there will be initiatives
in Sweden aiming to replace them.
For several years there has been a discussion in Sweden about the lack of
competition on the district heating market. As a consequence, the government set up
a TPA (third-party access) inquiry tasked with drawing up a regulatory framework for
third-party access to district heating networks. The inquiry presented its proposal for
regulated third-party access in spring 2011, which entailed an obligation for network
owners to allow access to producers or network owners wishing to distribute district
heating production. In a public consultation, the proposed TPA was criticised and the
proposal is therefore subject to further investigation. The government, however, has
publicly stated that a regulated TPA should be implemented in the district heating
market in order to improve competition.
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Chapter 23
Switzerland
Georges P Racine 1
I
OVERVIEW
The Swiss energy sector has its own distinctiveness. Switzerland has been referred to as
the ‘Water Tower’ of Europe; indeed, hydropower accounts for about 56 per cent of
electricity production in the country, while nuclear power accounts for about 39 per
cent. Other conventional thermal and ‘new’ renewable energies account for about 5 per
cent. 2
Despite the country’s high dependence on nuclear energy, the Federal Council
has decided to gradually phase out nuclear power. The safe operational lifespan of the
existing nuclear power plants is expected to be about 50 years. On this basis, the last of
Switzerland’s nuclear power plants would be taken offline in 2034. Switzerland seems
to be the only country to have made a complete about turn following the Fukushima
disaster.
The Swiss electricity market has also been described as highly fragmented due
to the number of market participants (about 1,000). Such a high number is peculiar
considering the size and population of the country.
Electricity represents approximately 23.6 per cent of Swiss energy consumption,
while oil and gas represent about 54.5 per cent and 12.7 per cent respectively. Coal,
wood, industrial waste and other renewable energies (biogas, sun, ambient heat, etc.)
constitute the remaining 9.2 per cent. 3
As a landlocked mountainous country and non-EU member, which is located at
the heart of Europe, Switzerland must implement its energy policy wisely. At the same
1 Georges P Racine is a partner at Lalive and a director of Lalive in Qatar LLC. The author would
like to thank Leonor Díaz de Córdova for her assistance in researching materials for this chapter.
2 www.bfe.admin.ch/themen/00612/index.html?lang=en; www.bfe.admin.ch/themen/00490/
index.html?lang=en.
3 http://www.bfe.admin.ch/themen/00490/index.html?lang=en.
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time, certain decisions may naturally impose themselves despite any political opposition
and the tendency towards renewable forms of energy.
Switzerland produces neither oil nor gas. Despite the fact that there are indications
that the exploitation of shale gas could be possible in certain parts of the country, this
chapter on Switzerland focuses on the electricity industry.
II
REGULATION
i Policy
The Swiss Federal Constitution, the Energy Act, the CO 2
Act, the Nuclear Energy Act and
the Electricity Supply Act are all integral parts of the instruments defining a sustainable
and modern Swiss energy policy. In addition to legal instruments, the energy policies
of the federal government and the cantons are also based on the presentation of energy
perspectives as well as on strategies, implementation programmes and the evaluation of
energy-related measures at the municipal, cantonal and federal levels.
Energy policy was only anchored in the Swiss Federal Constitution in 1990, when
provisions were added stipulating that the federal government and the cantons are obliged
to use their competences to ensure an adequate, broad-based, secure, economical and
ecological energy supply, and the economical and efficient use of energy. This comprehensive
list of requirements places high demands on energy policy at the federal and cantonal levels,
and simultaneously demonstrates how difficult it is to find suitable solutions.
Since 1990, all cantons have drawn up their own energy legislation and regulations,
and with the enactment of the Federal Energy Act and the Federal Energy Ordinance on
1 January 1999, the Federal Council fulfilled the mandate it had received following the
approval by the electorate of the energy provisions in 1990.
The energy perspectives as drawn up by the Federal Council have served as a
basis for all political decisions in the energy field and have been reviewed and updated
regularly since the establishment of the General Energy Plan in the mid-1970s.
The ‘Energy Perspectives 2050’ have been updated after choosing between
three options for the provision of electricity. In 2011, the Federal Council decided to
follow option 2 (no replacement of existing nuclear power plants at the end of their safe
operational lifespan).
Non-replacement of older nuclear power plants restricts the options for future
electricity production. After the safe operating period expires nuclear power plants will
not be replaced and will be decommissioned (Beznau I: 2019; Beznau II and Mühleberg:
2022; Gösgen: 2029; Leibstadt: 2034). The shortfall is expected to be covered with an
optimised mixture of hydropower, new renewable energies, cogeneration facilities, gas
combined cycle and electricity imports. Hydropower becomes very significant and will
have to be expanded correspondingly.
As thermal generation using fossil fuels will increase, additional emissions of 1.09
to 11.92 million tonnes of CO 2
are anticipated by 2050, depending on the proportion of
cogeneration and gas combined cycle. The government is hopeful that CO 2
emissions from
the energy sector will be reduced by 14.4 million tonnes compared with 2009 by pursuing
measures in today’s energy policy until 2050, which means that overall emissions will not
increase despite increased generation using fossil fuels. Electricity grids will have to be
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extended and rebuilt and transformation of distribution grids to smart grids will become
compulsory. Optimal connection to the European grid will have to be guaranteed.
According to initial calculations, the cost to the economy for modernising and
constructing power plants and measures to reduce electricity demand amount to about
0.4 to 0.7 per cent of gross domestic product.
In order to cover the shortfall in the electricity supply caused by the decision not
to replace the nuclear power plants, Switzerland’s energy strategy has to be revised. The
Federal Council has therefore set the following priorities:
a Reduction in energy consumption: the new energy outlook shows that the
demand for energy could rise to around 90 billion kWh a year by 2050 if tighter
measures are not put in place (2010: around 60 billion kWh). The main reasons
for this are population growth, increasing duplication of household appliances,
new appliances and applications, greater living space per person, but also the
increasing electrification of transport. The Federal Council therefore intends to
encourage the economical use of energy in general, and of electricity in particular.
Enhanced efficiency measures include minimum requirements for appliances (best
practice, energy label) and other regulations, bonus-malus mechanisms (efficiency
bonus), measures to raise public awareness (strengthening of SwissEnergy) and
measures regarding the production of heat.
b Broadening of electricity supply: hydropower and new renewable energies should
be bolstered in particular. Their share in the current energy mix needs to be expanded
significantly. That is the main aim of cost-covering remuneration for feed-in to
the electricity grid. However, in order to meet demand there also needs to be an
expansion of fossil fuel-based electricity production with cogeneration (combined
heat and power) (firstly) and gas-fired combined-cycle power plants (secondly).
The Federal Council is retaining its climate policy objectives. The increasing share
of irregular power production (wind, solar) requires a restructuring of the pool of
power plants to ensure the necessary storage and reserve capacities. Furthermore,
the conflict of interests between efforts to protect the climate, waterways and
countryside and spatial planning has to be resolved constructively.
c Maintaining electricity imports: imports will continue to be necessary to
ensure security of supply and to cover temporary fluctuations; however, the
Federal Council is of the opinion that Switzerland should continue to remain as
independent as possible in terms of electricity production.
d Expansion of electricity transmission grid: the rapid expansion of the electricity
transmission grid and the transformation of transmission networks into smart
grids is essential for future domestic production infrastructures and electricity
imports. These ‘intelligent’ grids allow direct interaction between consumers, the
network and power producers and offer great potential with regard to optimising
the electricity system, delivering energy savings and consequently bringing down
costs. Switzerland’s power grid should be optimally integrated into the European
grid and the future European ‘supergrid’.
e Strengthening energy research: the restructuring of the energy system needs to
be supported by the strengthening of energy research. To that end, the energy
research portfolio in the ETH (Federal Institute of Technology) Domain and at
the universities of applied sciences should be reviewed and cooperation between
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f
g
h
universities, business and centers of technological expertise encouraged. A plan
of action on ‘Coordinated Energy Research Switzerland’ with relevant roadmaps
should be drawn up for efficiency enhancing technologies, power grids and the
storage and distribution of electricity. The necessary federal funding for pilot
schemes and demonstration facilities should also be provided. These efforts are to
be coordinated with measures contained in the Cleantech Masterplan.
Confederation, cantons, cities and communes set the example: the Confederation,
the cantons, cities and communes will lead by example. They should meet their
own electricity and heating needs through renewable sources of energy and apply
the principle of best practice in all fields. The private sector should also play its
part in taking measures to reduce commercial energy consumption and strengthen
Switzerland’s position as a location for business by coming up with innovative,
energy-saving products. The energy industry should seize the opportunity to play
an active part in reshaping the national energy system and make the necessary
investments.
Beacon projects guide the way: pilot and demonstration projects developed by
various industries and groups should provide valuable experience for Switzerland’s
future in terms of energy. The fields of Smart Buildings, Smart Cities, Smart Grids
and district heating networks are key in achieving an optimisation of the energy
system, and thus contributing to a reduction in energy consumption, emissions
and costs.
Encouraging international cooperation: international cooperation in the field
of energy should be further intensified. Efforts should be made to conclude an
agreement on electricity with the European Union in 2012. In addition, contacts
with neighbouring countries should be intensified. Furthermore, Switzerland will
actively participate in the international debate on the future role and direction
of the International Atomic Energy Agency (IAEA) and take part in the relevant
political and technical conferences.
The Federal Department of the Environment, Transport, Energy and Communications
(‘DETEC’) will continue to develop the strategy in line with the decisions taken by
parliament together with the relevant departments and set out the measures to be
examined regarding implementation. In order to finance the necessary additional
measures, the Federal Council is studying the possibility of introducing an incentive tax
or ‘energy cent’. 4
ii Regulatory framework
Articles 76 and 89 to 91 of the Swiss Federal Constitution address energy matters and
bind the Confederation and the cantons to provide a satisfactory, diversified, secure,
economic and environmentally compatible energy supply.
4 www.bfe.admin.ch/themen/00526/index.html?lang=en; www.admin.ch/aktuell/00089/index.
html?lang=en&msg-id=39337; www.news.admin.ch/NSBSubscriber/message/attachments/23232.
pdf; www.bfe.admin.ch/energie/00572/00575/index.html?lang=en.
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Switzerland
According to the Constitution, the Confederation is in charge of determining
the principles of the use of domestic and renewable energies, as well as legislating in
certain specific areas such as nuclear energy, hydropower generation and transmission
and delivery of electricity. Legislation concerning all other areas is to be provided by the
cantons. Consequently, energy can vary considerably among cantons.
At the federal level, the principal pieces of legislation are:
a Energy: Energy Act 1998
b Hydropower: Hydropower Act 1916
Water Protection Act 1991
d Electricity: Electricity Act on Electric Facilities for Low and High Voltage 1902
Electricity Supply Act 2007
e Nuclear: Nuclear Energy Act 2003
F federal Inspectorate Nuclear Security Act 2007
Liability in Nuclear Matters Act 1983
f CO 2
: CO 2
Emission Reduction Act 1999
g Pipelines: Pipelines Act 1963
The Federal Electricity Supply Act, which was adopted by Parliament in 2007, provides
for an opening of the market in two stages starting on 1 January 2009. In the first five
years (2009 to 2013), only end-consumers with an annual consumption of more than
100,000kWh per site are granted free access to the market. After this period, households
and other small-scale end consumers will be able to freely choose their electricity supplier.
Alternatively, it is possible to remain a ‘captive consumer’ and continue to purchase
electricity at capped prices. Full market liberalisation will be introduced on the basis of
a federal resolution, which will be subject to an optional referendum (therefore, there
is no certainty as to whether the second phase will become a reality). The high-voltage
network must be operated by the national transmission system operator (Swissgrid) with
a majority Swiss holding.
The main objective of market liberalisation – the creation of a competitive and
secure electricity supply with transparent pricing – has not been achieved to date. A
lack of market transparency, non-competitive behaviour by the involved players and
the continued threat of sharply rising electricity tariffs, endangering the international
competitive capacity of energy-intensive companies, indicate that a thorough analysis
of the applicable legislation is called for (Swiss legislators did not expect European
electricity prices to increase to a level that would make it more attractive to remain
captive than to purchase electricity at market prices). At the end of 2009, a revision of
the Act begun. It is expected that the EU 3rd Energy Package will be factored into the
revision. The introduction of incentive regulation is also being considered. The initial
aim of the revised Electricity Supply Act to enter into force in 2014, to coincide with the
second stage of market liberalisation, has been postponed (at least) for a year.
Since the end of 2007, negotiations between the EU and Switzerland to enter into
a comprehensive long-term energy treaty have been ongoing. The primary aim of such an
accord (obtaining this agreement is considered one of the top priorities for Switzerland)
would be the mutual access to the free energy market. The legal developments within
the EU will be taken into consideration, namely the 3rd Energy Package, in relation to
which Switzerland is aspiring to become a member of newly established organisations
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such as ENTSO-E (European Network of Transmission System Operators for Electricity),
ENTSO-G (European Network of Transmission System Operators for Gas) and ACER
(Agency for the Cooperation of Energy Regulators). In addition, safety standards will be
harmonised and there will be negotiations regarding mutual recognition of guarantees of
origin for electricity from renewable sources and of CO 2
emission rights. Switzerland would
have to commit to binding national targets in relation to the share of renewable energy. 5
iii Institutional framework
The Swiss energy institutional framework comprises a number of federal offices,
regulatory authorities and specialised agencies. The Federal Office of Energy (‘the FOE’)
is the office responsible for all questions relating to energy supply and energy use. It
sits under DETEC, which is responsible for ensuring sustainable development and the
provision of basic public services in the interests of society, the environment and the
economy.
The FOE pursues the following objectives:
a it creates the necessary conditions for ensuring a sufficient, well diversified and
secure energy supply that is both economical and ecologically sustainable;
b it imposes high safety standards in the areas of production, transportation and
distribution of energy;
c it sets out to promote efficient energy use, increase the proportion of renewable
energy in the overall energy mix and reduce the level of CO 2
emissions; and
d it promotes and coordinates energy research and supports the development of
new markets for the sustainable supply and use of energy.
A number of commissions support the FOE, including the Energy Research Commission
(‘the CORE’), the Commission for Radioactive Waste Disposal (‘the CRW’), the
Administrative Commission of the Decommissioning Fund and the Disposal Fund for
Nuclear Installations (‘the ACDFDFNI’), the Nuclear Safety Commission (‘the NSC’)
and the Commission for Connection Conditions for Renewables Energies (‘the CCRE’).
The CORE assists with the formulation of guidelines governing energy research
and the implementation of research findings. Its members represent the industrial sector,
the energy industry, universities and various energy agencies and research institutions in
Switzerland.
The CRW is an independent body that is responsible for advising the FOE and
the Federal Nuclear Safety Inspectorate (‘ENSI’) (see below) on geological aspects of
nuclear waste disposal.
The two funds administered by the ACDFDFNI were established for the purpose
of securing the necessary financing for the disposal of radioactive waste and spent-fuel
elements, and the decommissioning of nuclear installations after their shutdown.
As an advisory body for the Federal Council, the DETEC and the ENSI, the
NSC examines fundamental issues relating to nuclear safety and may submit comments
for the attention of the Federal Council and the DETEC regarding reports by the ENSI
5 www.admin.ch/ch/f/rs/73.html; Legal Framework v2.docx.
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on nuclear safety. It took over the duties of the former Federal Commission for the Safety
of Nuclear Facilities on 1 January 2008.
The CCRE advises cantonal authorities and the FOE on the formulation
of recommendations and enforcement tools for the implementation of connection
conditions for independent producers. 6
The Federal Office for the Environment (‘the FOEN’), which also sits under the
DETEC, plays an important role alongside the FOE. It is responsible for ensuring that
natural resources are used sustainably, that the public is protected against natural hazards,
and that the environment is protected from unacceptable adverse impacts.
In accordance with DETEC’s sustainability strategy, the FOEN pursues the
following goals:
a long-term preservation and sustainable use of natural resources (land, water,
forests, air, climate, biological and landscape diversity) and elimination of existing
damage;
b protection of the public against excessive pollution (noise, harmful organisms
and substances, non-ionising radiation, wastes, contaminated land and major
incidents); and
c protection of people and significant assets against hydrological and geological
hazards (flooding, earthquakes, avalanches, landslides, erosion and rockfalls).
In order to achieve these goals, the FOEN has been assigned the following responsibilities:
a environmental monitoring, to provide a sound basis for the management of
resources;
b preparation of decisions, to secure a comprehensive and coherent policy of
sustainable management of natural resources and prevention of natural hazards;
and
c implementing the legal foundations, supporting enforcement partners and
providing information on the state of the environment and on the appropriate
use and protection of natural resources. 7
The Federal Electricity Commission (‘ElCom’) is the independent regulatory authority
for the electricity sector. It is responsible for monitoring compliance with the Federal
Electricity Act and the Federal Energy Act, taking all necessary related decisions and
pronouncing rulings where required.
When the new Electricity Supply Act entered into force on 1 January 2008, ElCom
was formally entrusted with the task of supervising the liberalisation of Switzerland’s
electricity market. As an independent regulatory authority at the federal level, ElCom
is responsible for securing the smooth transition from a monopoly situation in the
electricity supply sector to an electricity market based on the principles of competition.
ElCom’s duty is to ensure that the liberalisation of the market does not result in excessive
6 www.uvek.admin.ch/index.html?lang=en; www.bfe.admin.ch/index.html?lang=en.
7 www.bafu.admin.ch/?lang=en.
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tariff increases and that the network infrastructure is properly maintained and expanded
in order to guarantee an adequate supply of electricity.
ElCom has been entrusted with extensive judicial powers so that it can effectively
perform its various duties. It monitors compliance with the provisions of the Electricity
Supply Act and the Energy Act, and can pronounce legally binding decisions and rulings
as necessary.
The specific duties of ElCom are to:
a verify the electricity tariffs of customers who do not have free access to the
network, as well as remuneration paid for the input of electricity into the grid. It
is authorised to prohibit unjustified increases in electricity prices, or may order the
reduction of excessively high tariffs. It may take action on the basis of complaints
or in its official capacity;
b mediate and pronounce rulings on disputes relating to free access to the electricity
network. Since 1 January 2009, large-scale consumers can freely choose their
electricity supplier. Small-scale consumers will only have access to the electricity
network from 2014, assuming that no referendum should be called opposing the
full liberalisation of the electricity market;
c rule on disputes relating to cost-covering remuneration of input of electricity that
is to be paid to producers of electricity from renewable energy sources with effect
from 2009;
d monitor the situation with respect to supply security and the condition of the
electricity networks;
e in the case of shortfalls in cross-border transmission lines, to regulate the allocation
of network capacities and coordinate its activities with the European electricity
market regulators; and
f ensure that the transmission network is handed over to the national system
operator (Swissgrid) according to schedule.
There are no specific regulatory authorities for oil and gas as Switzerland does not
produce any. 8
Two other key institutional players (specialist agencies) are the Federal Pipeline
Inspectorate (‘the FPI’) and the Federal Nuclear Safety Inspectorate (‘ENSI’).
The FPI supervises the planning, construction and operation of pipelines for the
transmission of gas and liquid fuels that are subject to the Pipelines Act. The FPI aims to
put the protection of human life and the environment above profitability. 9
ENSI is the national regulatory body with responsibility for the nuclear safety and
security of Swiss nuclear facilities. It is the successor body to HSK from whom it took
over on 1 January 2009. Whereas HSK was part of the FOE, ENSI is an independent
body constituted under public law. By passing the Federal Act on ENSI on 22 June
2007, the two parliamentary chambers in Switzerland resolved to turn HSK into an
agency of federal government constituted under public law and so complied with the
8 www.elcom.admin.ch/index.html?lang=en.
9 www.uvek.admin.ch/org/00469/02946/02960/index.html?lang=fr.
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Switzerland
requirements of the Nuclear Energy Act and the International Convention on Nuclear
Safety that regulators should be independent bodies.
ENSI is supervised by an independent board who is elected by the Federal
Council and reports directly to it. It is responsible for the supervision of nuclear facilities.
Its regulatory remit covers the entire life of a facility, from initial planning, through
operation to final decommissioning including the disposal of radioactive waste. Its
remit also includes the safety of staff and the public and their protection from radiation,
sabotage and terrorism. ENSI is also involved in the transport of radioactive materials to
and from nuclear facilities and in the continuing geoscientific investigations to identify a
suitable location for the deep geological disposal of radioactive waste. 10
III
ENERGY MARKETS
i Partial liberalisation
The Swiss electricity market has been partially liberalised since 1 January 2009. Only
larger consumers with an annual consumption of more than 100MWh, representing
more or less 50 per cent of the electricity demand in Switzerland, have so far benefited
from the market opening.
The separation of the transmission network is one of the key criteria in the
liberalisation of Switzerland’s electricity market. This concerns the network of highvoltage
transmission lines for transporting electricity over great distances. The aim here
is that ownership and operation of this network (monopoly) are to be separated from
other business activities such as electricity production and trading (market).
In practical terms, this means that companies which have held stakes in the
transmission network until now are required to assign these to the national transmission
system operator (Swissgrid). This process is to take place in three stages:
a separation of the accounts of the network owner/operator from other activities
(already implemented);
b legal separation, for example outsourcing of the network to a separate subsidiary
(was to be effected by no later than 1 January 2009); and
c transfer of network ownership to Swissgrid (to be effected by no later than 1
January 2013).
Swissgrid is the national grid company, and in its capacity as transmission system operator
it operates under the supervision of Elcom.
As a member of the European Network of Transmission System Operators for
Electricity (ENTSO-E), it is also responsible for coordination and grid usage in the
cross-border exchange of electricity in Europe.
Swissgrid is wholly owned by the Swiss electricity companies Alpiq AG, Alpiq
Suisse AG, Axpo AG, BKW FMB Energie AG, Centralschweizerische Kraftwerke AG
(CKW), Elektrizitäts-Gesellschaft Laufenburg AG (EGL), Elektrizitätswerk der Stadt
10 www.bfe.admin.ch/radioaktiveabfaelle/01275/01292/index.html?lang=en.
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Zürich (ewz) and Repower AG. The companies are directly or indirectly majority-owned
by the cantons and the municipalities. 11
The Swiss energy market comprises nearly 1,000 players, including just over
a handful of major consortia (known as Überlandwerke) with vertically integrated
operations, and about 80 power producers, who differ considerably in terms of size
and operations. The vast majority of market players are publicly owned regional and
local utilities that distribute electricity to their local municipalities. Only some of these
regional and local distributors can produce electricity. The largest utilities are responsible
for approximately 80 per cent of the power production and 90 per cent of the energy
supplied in the country.
The liberalisation of the Swiss electricity market and integration with the European
market is expected to lead to a rapprochement of the Swiss electricity players.
ii Electricity trading
Cross-border trading of electricity is important for Switzerland due to its location in the
heart of Europe.
As there is no power exchange in Switzerland, Swiss trading companies trade on
the Powernext in Paris, the Energy Exchange in Austria (EXAA) and the Leipzig-based
European Energy Exchange (EEX).
The Dow Jones Swiss Electricity Price Index (‘the SWEP’), which was initiated
by Aare-Tessin AG für Elektrizität (ATEL) and Elektrizitäts-Gesellschaft Laufenburg AG
(EGL), and launched in cooperation with Dow Jones in March 1998, provides price
indications for over-the-counter electricity trading in Switzerland for next-day delivery.
The SWEP is the volume-weighted average of the profile adjusted price for hour 12 of all
transactions having an impact on hour 11 a.m. to 12 p.m., also taking into account the
Index for the past 20 days. 12
IV
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Historically, Switzerland’s longest-serving and most important source of renewable
energy has been hydropower, but the ‘new’ renewables including solar, wood, biomass,
wind, geothermal and ambient heat also play an increasingly important role in today’s
Swiss energy mix. The long-term potential of domestic renewable energy indicate that,
for all forms, the prospects for electricity and heat are sound; however, it is also clear that,
primarily for economic reasons, it will only be possible to fully utilise the major potential
of photovoltaic or geothermal energy in approximately 30 years’ time. Other renewables
such as wood and biomass, ambient heat, electricity from small-scale hydropower plants
– and, to a modest extent, wind – are available now and in some cases are also already
economically attractive.
11 www.swissgrid.ch/swissgrid/en/home.html.
12 www.djindexes.com/mdsidx/?event=energySwPower.
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With the introduction of remuneration at cost for input into the grid, one of the
goals of Switzerland’s energy policy is to increase the proportion of electricity produced
from renewable energy by 5,400GWh (or 10 per cent of the country’s present-day
electricity consumption) by 2030. At 2007, approximately 55.6 per cent of Switzerland’s
overall electricity production came from renewable sources, with hydropower by far the
biggest contributor (96.5 per cent). 380 electricity supply companies now offer certified
electricity products from renewable energy, which meet 4.5 per cent of Switzerland’s
electricity demand.
‘New’ forms of renewable energy currently contribute around 5.7 per cent towards
Switzerland’s electricity production today. Of the latter 5 per cent, about 3.72 per cent
comes from biomass (wood and biogas), followed by use of ambient heat (about 0.79 per
cent) and waste from incineration plants (about 0.47 per cent). Smaller contributions
come from solar energy (about 0.13 per cent) and wind energy (about 0.004 per cent). 13
Since 1 January 2009, operators of new facilities producing electricity from
renewable energy – small-scale hydropower plants with a capacity up to 10MW, and
facilities using solar energy, geothermal energy, wind energy, biomass and waste from
biomass – have received an additional combined total of approximately 320 million Swiss
francs per annum. The aim here is to promote the use of environmental technologies for
the production of electricity. Remuneration for the input of electricity into the grid is
financed through a surcharge of 0.6 cents per kilowatt hour (currently 0.45 cents per
kWh) on the electricity tariff.
Swissgrid is part of this initiative, which promotes effective integration of 100 per
cent of electricity produced from renewable energy sources. It advocates national and EU
authorities to strive for an efficient, sustainable, clean and socially accepted development
of the European network infrastructure for both decentralised and large-scale renewable
energies.
The Swiss government is looking into tax reforms to encourage ‘green’ activities
such as energy conservation and anti-pollution measures. The hope is that such tax
reforms could help reduce energy consumption and eliminate Switzerland’s dependence
on nuclear energy by 2050. The goal is not to increase tax volume; rather, the idea is to
reform the tax system without creating a tax burden on businesses or households.
Two potential systems are under consideration: one would compensate taxpayers
for any ecological measures they take by reducing their taxes elsewhere, while in the other
model, they would receive money directly.
The government has asked the finance ministry to collaborate with the
environment, transport and energy ministry to see how these systems might work and to
make some recommendations by the middle of 2012.
Green parties and organisations, the centre-left Social Democrats and the centreright
Christian Democrats generally welcomed moves to reform the tax system to benefit
the environment, although some found the plans too tame. But the centre-right radicals
13 www.bfe.admin.ch/themen/00612/index.html?lang=en; www.bfe.admin.ch/themen/00490/
index.html?lang=en.
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said the government lacked a clear energy strategy, and the right-wing People’s Party said
ecotaxes would overburden energy-intensive industries.
ii Energy efficiency and conservation
Energy efficiency and conservation is at the forefront of the Energy Strategy 2050.
Switzerland has to confront in the coming years not only the problem of excessive
greenhouse gas emissions, but also a shortage of available energy.
Improving energy efficiency is the main tool to reduce energy consumption
without loss of benefits. Greater energy efficiency helps to achieve a desired value (e.g.,
generation of light, providing heat, driving a motor) with less energy expenditure.
Increasing the energy efficiency brings three main benefits: increased economic efficiency,
reduce energy shortages and reduce the energy consumption linked to greenhouse gas
emissions. Reducing energy consumption through increased energy efficiency will allow
only that it will be realistic in the future to cover a substantial portion of the Swiss energy
consumption through renewable energy.
In this sense, the FOE supports the development, dissemination and application
of technologies to improve energy efficiency and measures to counteract the lack of
information in households and industry on energy efficiency. In addition, the FOE will
contribute to the promotion of energy production from renewable resources so that the
remaining requirements can largely be met on renewable energy in the future.
V
OUTLOOK
The three oldest Swiss nuclear power plants were to be retired around 2020 after some 50
years of operation. Before the Fukushima disaster, three permit applications for new (i.e.,
replacement) nuclear power plants had been filed. Legislation mandates parliamentary
approval for new nuclear power plant permits. Any parliamentary decision may be
challenged in a referendum, so referenda in 2013–14 against new nuclear power plants
would have been more than likely, as public opinion was only narrowly pro‐nuclear.
On 13 February 2011, in a consultative ballot, the people of the Canton of Bern had
approved a new nuclear power plant to replace the ageing Mühleberg nuclear power
plant with a 51.2 per cent majority.
After the Fukushima disaster, however, the application procedures for the three
new nuclear power plants were suspended. Polls indicated that more than 80 per cent
of the population had turned against nuclear, thereby thwarting any new nuclear power
plant project. Two months later, the Federal Council made public its decision to phase
out nuclear power and not replace the existing nuclear power plants.
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Chapter 24
Turkey
Zeynel Tunç 1
I
OVERVIEW
Turkey’s general energy policy is to maintain a high-quality, reliable, continuous and costeffective
supply while maintaining a liberal, competitive, transparent, non-discriminatory
and stable market. Additionally, Turkey intends to reduce its dependence on imported
energy. To achieve these ends, the Turkish government has been reforming its energy laws
while trying to promote private investment in its energy market. Recent trends, in particular
in the electricity and renewable energy sectors, show an even stronger push towards
privatisation that corresponds with the growth of Turkey’s economy and population. As
such, this chapter will focus exclusively on Turkey’s electricity law, the developments taking
place in the privatisation of its electricity market and on renewable energy.
Following the reform programme and the opening up of the Turkish economy
in the 1980s, the statutory monopoly of the Turkish Electricity Company (‘TEK’) was
abolished by the Electricity Act in 1984, and it became possible for private companies to
engage in electricity generation activities under the transfer of operating rights (‘TOOR’)
and build–operate–transfer (‘BOT’) contracting models. The main objective of the
Electricity Act was simply to provide authorisation to private companies rather than
giving concessions. The Council of State (‘the Daniştay’), however, decided in 1996 that
transferring electricity generation activities through the TOOR and BOT contracting
models was just another way of giving concessions; this decision led to a change in
the concession law to govern the implementation of these contracting models. In time,
four different contract models were used to attract private investors, including the
BOT, build–own–operate (‘BOO’), autoproducer and TOOR models. The BOT and
BOO approaches had attracted substantial new power plant investments because these
approaches had purchase and payment guarantees, which were backed by guarantees
issued by the Turkish Treasury.
1 Zeynel Tunç is a senior associate at Paksoy Attorneys at Law.
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In the meantime, TEK was unbundled in 1993 into two state-owned entities,
the Turkish Electricity Generation Transmission Company (‘TEAŞ’) and the Turkish
Electricity Distribution Company (‘TEDAŞ’). The unbundling of TEK was then
followed by TEAŞ’s restructuring and TEAŞ was further unbundled into the following
three state-owned public enterprises:
a the Turkish Electricity Transmission Company (‘TEİAŞ’), established to carry out
electricity transmission activities, system and market operation;
b the Electricity Generation Company (‘EÜAŞ’), established to carry out electricitygeneration
activities until such activities are fully privatised; and
c the Turkish Electricity Trading and Contracting Company (‘TETAŞ’), established
to carry out electricity wholesale activities for handling stranded costs.
These three companies, together with TEDAŞ, which was established for carrying out
electricity distribution activities, are the state-owned players in the Turkish electricity
market.
As a result of Turkey’s financial crises from 1998 to 1999 and again in 2001, and
from subsequent IMF pressure originating from its monetary and policy assistance to
Turkey, the Turkish government had no option but to stop providing Treasury guarantees
for investment carried out by the private sector. Having failed in making long-overdue
energy investments due to lack of funds, Turkey felt the need to liberalise its market
to overcome the growing energy issues in the country. Consequently, in response to
the need for sustainable private involvement in the electricity sector, the government
embarked on a far-reaching reform programme to create a competitive market structure
with separate generation and distribution firms that may gradually be privatised. As
such, motivations by the Turkish government to engage in power sector reform and to
open its power sector to competition were driven by the high cost of energy supply, the
high unreliability of the system, and the significant underinvestment in energy.
During the course of this liberalisation process, a new legal framework for the
Turkish electricity market was introduced by the passage of the Electricity Market Law
No. 4628 (‘the EML’) in 2001. 2 The EML and the secondary regulations following the
passage of the EML cover the generation, transmission, distribution, wholesale, retail
and other respective services of electricity, including its import, export and the rights and
responsibilities of individuals receiving those services related to electricity. Furthermore,
a regulatory body, the Energy Market Regulatory Authority (‘EMRA’), was established
to oversee the market players and activities.
Finally, in addition to passing various secondary legislations under the EML, the
Turkish government has recently proposed a set of new amendments to the EML that
will further reform the electricity market (‘the Draft EML’). If the current form of the
Draft EML is passed by the Turkish parliament, it will substantially alter the current
market regime. In addition, the Draft EML would change the types of licence that are
issued by the Turkish government and the powers of the government organisations in
charge of regulating the energy market.
2 Published in the Official Gazette No. 24335 dated 3 March 2001.
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II
REGULATION
i
The regulators
Broadly speaking, Turkish energy policy is determined by the Ministry of Energy and
Natural Resources (‘the MENR’), while the market regulator is EMRA. EMRA is an
autonomous, public legal entity with administrative and financial authority to regulate
and monitor electricity, natural gas, petroleum and the liquid petroleum gas markets.
This entity is considered to be part of the executive branch, is affiliated with MENR,
and has independent regulatory power. EMRA is governed by the Energy Markets
Regulatory Board.
EMRA has the authority to create and approve tariff levels, issue licences, establish
quality service standards, and address certain other matters such as management and
consumer complaints arising from lack of quality or interruptions in the power supply.
EMRA often cooperates with the Turkish Competition Authority, and its decisions may
only be appealed to the Daniştay.
ii Regulated activities
The first part of the EML sets out the law’s goals and objectives, as well as the types of
market activity to be conducted, the policies for state-owned companies, the categories
of legal entities in the market and the types of restrictive licences to be issued, and the
conditions for granting them. The types of market activity that are regulated by the
EML are generation, transmission, distribution, wholesale activities, retail sale services,
and the import and export of electricity. Each market activity requires a licence to be
issued by EMRA. For generation activities, legal entities are required to obtain a separate
generation licences for each generation facility.
The application procedure for obtaining the licences is set out under the
Electricity Market Licencing Regulation (‘the Licensing Regulation’). 3 Accordingly, the
licence applicant must compile all the documents listed in the Licensing Regulation and
apply to EMRA. If EMRA determines that the application is complete and accurate,
it notifies the applicant in writing and the applicant pays 1 per cent of the licence fee
within 10 business days. 4 The non-payment of this portion of the licence fee results
in EMRA’s rejection of the application. EMRA’s assessment of a licence application
is based on a multitude of factors, including without limitation, conformity with the
objectives set forth in the relevant legislations, protection of consumer rights and the
impact on development of the competition and the market, and the experience of the
applicant in domestic and foreign markets. The Licensing Regulation also provides a
catch-all provision for EMRA’s application assessment process. Accordingly, EMRA may
request additional information or documents, and may call on the persons authorised to
represent the applicant to discuss the application for purposes of its assessment.
3 Published in the Official Gazette No. 24836 dated 4 August 2002.
4 The licence fees for the following years are announced annually by EMRA on its website.
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iii
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Ownership and market access restrictions
Foreign investors may invest in the Turkish energy market by participating with, or
establishing, a Turkish legal entity holding a licence. There are no indigenous shareholder
requirements for licence-holding entities, and foreign investors may own 100 per cent of
the shares in a licence holding company, subject to Article 14(3) of the EML; however,
there are some market restrictions applicable. First, total market share of generation
facilities operated by individual private-sector generation company and their affiliates
may not exceed 20 per cent of the published figure for the total installed capacity in
Turkey in the previous year. Second, autoproducers and autoproducer groups can only
sell 20 per cent of the average amount of electricity generation to the market in a calendar
year, which is incorporated in their licences. Third, the total market share of any private
sector wholesale company, together with its affiliates, may not exceed 10 per cent of the
total electricity consumed in the market in the previous year.
iv Transfers of control and assignments
The direct or indirect acquisition of more than 10 per cent of shares of a licence-holder
company (or 5 per cent in publicly offered companies) is subject to EMRA’s approval.
In addition, share acquisitions that result in the ownership of more than 10 per cent
of the licence holder’s capital or share transfers that leads to decrease in a shareholder’s
shares below the aforementioned rate are also subject to the EMRA’s approval. Mergers,
consolidations, change of control, change in the structure of these companies, or a
change in the generation, transmission or distribution facilities of a company through a
sale, transfer or any other means, are also subject to EMRA’s approval.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Transmission and distribution access
Transmission activity in Turkey can only be carried out by TEİAŞ under its transmission
licence, which is not encompassed by the privatisation programme. Due to the
monopolistic nature of transmission, TEİAŞ must treat all parties equally. Also, according
to the Licensing Regulation, TEİAŞ must plan the connection needs of all third parties.
This regulation further provides that TEİAŞ is required to provide an opinion on the
suitability for connection of generation and autoproducer licence applicants within 45
days, and it must provide its reasoning if its opinion is to reject the application. Likewise,
a connection request by third parties in distribution areas must also be handled according
to equal treatment principles.
In addition, the regulation prohibits TEİAŞ, or a distribution company, to
prevent an eligible customer to choose its suppliers and its connection and system usage
rights. For example, neither TEİAŞ nor a distribution company may reject a connection
or system usage request unless:
a the network is technically insufficient at the time of the requested connection
point;
b the facility does not comply with connection standards set out in the legislation;
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c
d
e
the requested connection has a preventive impact on TEİAŞ or a distribution
company’s public service obligations (this must be evidenced by TEİAŞ or the
distribution company);
the facility will cause a decrease in the electricity quality of the system; or
with respect to wind and solar facilities, there is an alternative connection point
that is more economical and efficient.
Furthermore, once connected to the system, if there is a need for a system usage capacity
increase or a new investment and there is insufficient financing for such an investment,
then third parties requiring the connection may make the necessary investment in
accordance with any required standards on behalf of TEİAŞ or the distribution company.
In such circumstances, the total investment amount may be set off from the system usage
fees or distribution tariffs under the connection agreement that will be executed between
the parties.
Last, it should be noted that TEİAŞ or the distribution company must give
priority to those facilities with renewable energy sources and facilities with indigenous
natural resources.
ii Tariffs
EMRA creates the principles and procedures for setting certain tariffs, and it reviews and
approves the methodologies and tariffs submitted by certain other authorities. Article
13 of the EML and the Electricity Market Tariff Regulation set out the criteria for the
preparation of tariff proposals by TEİAS, TETAŞ and other entities. Generally, tariffs
must be cost-effective and are created ex ante according to a pre-defined methodology.
Once they have been approved they are published in the Official Gazette and on EMRA’s
website to ensure transparency. Broadly speaking, there are eight categories of tariffs:
connection, transmission, distribution, average wholesale price, wholesale price for
TETAŞ, retail supply, retail supply services and ancillary services.
Also, as described below, Turkey has passed laws with respect to renewable energy,
which provide incentives and benefits for renewable energy projects, including feed-in
tariffs. These tariffs are applicable to entities holding generation licences that started
operation between 31 December 2005 and 18 May 2008, and lasts for 10 years from the
date of operation.
iii Supply security
The MENR is responsible for monitoring the security of the electricity supply and for
taking measures to protect it. In 2008, the EML was amended to ensure the security
of the electricity supply and to provide new measures to prevent a supply deficit. For
example, it increased the powers of MENR so that it is authorised to take any measure
to secure the supply of electricity. Also, it is tasked with preparing a report on electricity
security for each fiscal year. Moreover, it may announce a tender if energy investments
are insufficient to meet demand.
In addition to increasing the authority of the MENR, the 2008 EML amendment
also made TEİAŞ responsible for ensuring the reliability of the grid. While doing so,
TEİAŞ must meet third-party demands for connection to the network and system use on
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a non-discriminatory basis, which is also done in an environmentally friendly manner.
Furthermore, TEİAŞ is entitled to take any necessary measures and actions should there
be a threat to the reliability and safety of the transmission grid.
IV
ENERGY MARKETS
The EML provides the framework for the establishment of a market relying primarily
on physical bilateral contracts between market participants and the balancing (dayahead
and real-time) and settlement mechanism. The Electricity Market Balancing and
Settlement Regulation (‘the BSR’) describes the market parameters. Under the BSR, the
balancing of the system is conducted by TEİAŞ under its National Load and Dispatch
Centre. TEİAŞ also has the Market Financial Settlement Centre, which handles monetary
transactions. The National Load and Dispatch Centre estimates hourly consumption
and this estimate is used as a guide for scheduling activities for the next day. Also, it
uses a day-ahead schedule that is based on consumer use and consumption estimates to
schedule how much electricity is needed 24 hours in advance.
Looking at the market’s evolution, the implementation of the market structure has
been in three transitional stages. The first stage took place between 2006 and 2009 and
was characterised by limited price bidding and regulated imbalance prices. The second
stage began in December 2009, when the balancing and settlement market began to
operate with limited and more competitive balancing prices and the day-ahead planning
of dispatch. The last stage has been the actual implementation of the day-ahead market,
which began full operation in December 2011.
In contrast with the balancing market’s main purpose of functioning as a net pool
with only small differences traded in the spot market, the balancing market was used as
a gross pool and a few contracts were signed between independent power producers and
distribution companies. This was due to:
a transitional agreements for distribution companies with purchase prices below
generation costs;
b
c
the creditworthiness of state-owned distribution companies; and
the tight supply-demand dynamics leading to attractive prices in the balancing
market.
In addition to the implementation of the day-ahead market and the progressive
privatisation of the distribution companies and generation assets, competitive bilateral
contract market and prices reflecting the long-run cost of generation are expected.
V
RENEWABLE ENERGY AND CONSERVATION
Part of Turkey’s energy policy is to reduce its dependence on importing foreign energy
sources by relying more on the forms of renewable energy that the country is able to
produce. The Turkish government and the private investment community believe that
Turkey’s geographical and climate conditions are well suited for the continued growth
of this sector with the generation of wind, solar and geothermal power. As such, the
World Bank recently announced in 2011 that it will provide $500 million to help fund
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the private sector’s investments in renewable energy, which would be guaranteed by the
Republic of Turkey. 5 These monies are in addition to an initial World Bank funding of
$500 million and the financing by the Clean Technology Fund in the amount of $100
million that were made in 2009. 6
The renewable energy sector has been growing since 2005 when Turkey passed the
Law on the Utilisation of Renewable Energy Resources for the Purpose of Generating
Electrical Energy, 7 amended in 2010. This law defined renewable energy sources as
electrical energy resources suitable for wind, solar, geothermal, biomass, biogas, wave,
current, tidal energy resources and hydraulic generation plants. Large hydroelectric power
plants, however, are not covered under this law. The purpose of this law was to promote
private investments in renewable energy and the liberalisation of electricity generation
using renewable and domestic resources. Also, it addresses the diversification of energy
resources, the reduction of greenhouse gas emissions, the reuse of waste of products and
the development of related manufacturing sectors to achieve these objectives. Pursuant
to this law, the government has pledged guarantees in the form of ‘purchase obligations’
for companies holding retail energy licences in renewable energy projects. This law
also allows for the development of small hydroelectric power plants, geothermal, solar,
biomass and wind power plants.
In 2006, the parliament passed an amendment to the Environment Law No.
2872 8 that allowed the use of the market and other financial tools, including carbon
trading, to promote renewable and clean energy technologies. It also imposed certain
emission fees. This amendment was followed up by the Energy Efficiency Law No.
5627, 9 which was passed in 2007, which provided a 20 per cent discount on electricity
costs of industrial enterprises signing a contract to reduce their energy use by 10 per
cent over a three-year period. Last, additional amendments were made to other laws that
furthered the government’s support of renewable energy.
In 2009, MENR issued a Strategy Paper 10 for 2010 to 2014 that outlines its goals
with respect to security and renewable energy. According to this strategy paper, Turkey
would like to increase its clean energy market share to 30 per cent by 2023, the 100th
anniversary of the Republic of Turkey.
Also, to further its commitment to renewable energy, the government recently
passed a law in 2010 with respect to the establishment of a generation facility based on
5 See ‘World Bank Makes $500M Cleantech Investment In Turkey (NewNet)’, available at
http://scherzerbeat.com/2011/11/world-bank-500m-cleantech-investment-turkey-newnet/.
6 See ‘Turkey Receives World Bank and First-Ever Clean Technology Fund Financing for
Renewable Energy and Energy Efficiency Program’, available at http://web.worldbank.org/
WBSITE/EXTERNAL/NEWS/0,,contentMDK:22194474~pagePK:64257043~piPK:43737
6~theSitePK:4607,00.html?cid=3001.
7 Published in the Official Gazette No. 25819, dated 18 May 2005.
8 Published in the Official Gazette No. 18132, dated 11 August 1983.
9 Published in the Official Gazette No. 26510, dated 2 May 2007.
10 See ‘World Bank Makes $500M Cleantech Investment In Turkey (NewNet)’, available at
http://scherzerbeat.com/2011/11/world-bank-500m-cleantech-investment-turkey-newnet/.
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wind park energy (known as the Rüzgar Enerjisine Dayali Üretim Tesisi Kurmak Üzere
Yapilan Lisans Başvurularina İlişkin Yarişma Yönetmeliği). 11 Prior to the passage of this
law, wind licences had been on hold indefinitely, which had resulted in investment delays
in this area; however, since the passage of this law, licences for numerous wind farms have
been issued. As this area continues to show improvement, some domestic companies
have been engaged in sourcing wind turbine components for their turbines in Turkey,
which will also help stimulate the country’s domestic market.
With respect to biomass projects and waste-to-energy projects, as of 2010, there
were 15 waste-to-energy facilities that use landfill gas. These facilities use an incineration
method that turns rubbish into electricity or steam to heat, cool, light and otherwise
power homes through the process of combustion; they are clean-burning facilities that
are environmentally friendly. The facilities currently in existence use a gasification process
or methane gas release from landfills to generate electricity. Also, Turkey is in the process
of developing modern waste-to-energy plants that are clean-burning using municipal
and commercial solid waste.
Some also believe that Turkey has great potential in the geothermal sector. There
are currently two such geothermal plants in operation, and several in the planning stage.
Also, there is some private investment interest in the solar energy market, but as of 2011,
solar energy remains untapped in the Turkish energy market.
VI
THE YEAR IN REVIEW
i The Draft Electricity Market Law
The Draft EML, which was recently published by the MENR, introduces major changes
in the current EML. If the Draft EML is passed by the Turkish parliament in its current
form, a pre-licencing process for generation activity and a rather different penalty regime
for distribution companies will be introduced. Additionally, there will be revisions made
regarding the types of licence issued, and the powers held by EMRA.
Market activities
According to the Article 4 of the Draft EML, market activities will be generation
activities, transmission activities, distribution activities, wholesale activities, retail sale
activities, market operation activities, export activities and import activities. As described
below, wholesale and retail sale activities will be carried out under the supply licence.
Changes in the types of licence
One of the major changes that the Draft EML introduces is that all wholesale and retail
sale activities are to be combined under a new single licence called the ‘supply licence’.
Supply licence holders will be able to carry out wholesale and retail sale activities without
any regional restriction. Temporary Article 12 of the Draft EML provides that existing
wholesale and retail sale licence holders will be granted a supply licence ex officio and free
of licence issuance charges. The supply licence will not prejudice licence holders’ rights
11 Published in the Official Gazette No. 27809, dated 8 January 2011.
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that they held under the existing wholesale and retail sale licences. The market share
restriction for these activities is 20 per cent. Accordingly, the total amount of electricity
supplied by a group of companies cannot exceed 20 per cent of the total electricity
consumed in the previous year in the market.
Furthermore, the Draft EML abolishes the concept of the autoproduction
licence, and autoproduction licences will be converted to generation licences. Therefore,
autoproduction licence holders will have to apply to EMRA for the issuance of a generation
licence by 31 December 2012. No licence issuance fee will be charged for this.
Preliminary licences
According to Article 6 of the Draft EML, a preliminary licence will be granted to
those companies intending to carry out generation activities. The scope of this licence
corresponds to the pre-construction stage incorporated under generation licences under
the current regime. During the term of this licence, the preliminary licence holder
must obtain the necessary permits, approvals and licences and other similar required
documents, including the ownership or usufruct right to the area on which the generation
facility will be installed. The term of the preliminary licence cannot be longer than 24
months irrespective of force majeure events. EMRA, however, may extend the term of
the licence by half of the preliminary licence period depending on the fuel source and
installed capacity of the plant that will be constructed. The preliminary licence concept
will be detailed by EMRA through forthcoming secondary regulations.
A preliminary licence will cease to be effective, if the licence holder does not:
a obtain the necessary permits, approvals and licences;
b prove that it has obtained the ownership or usufruct right to the area on which
the generation facility will be installed; or
c fulfil its obligations as determined by EMRA.
Furthermore, during the term of the preliminary licence, any change in the direct or
indirect shareholding of the preliminary licence holder, or the occurrence of a share
transfer or any transaction resulting in a share transfer (except by inheritance and
bankruptcy) will lead to cessation of the licence.
According to Temporary Article 11 of the Draft EML, a pending generation licence
application as of the effective date of the Draft EML will be assessed and concluded
as a preliminary licence application. Generation licence holders who are in their preconstruction
period or have not fulfilled their pre-construction period requirements
despite expiry of the pre-construction period under the licence may apply to EMRA
for an issuance of a preliminary licence within one month as of the effective date of the
Draft EML. The term of the preliminary licence for this type of applications will be
the remaining pre-construction period plus an additional three months, and for those
applicants whose pre-construction period had already expired, the licence term will be
limited to the three additional months. If the generation licence holder does not apply to
EMRA for the issuance of a preliminary licence and it cannot fulfil its pre-construction
requirements within one month of the effective date of the Draft EML, its generation
licence will be cancelled and its performance bond that had been provided to EMRA will
be forfeited. Furthermore, a generation licence holder whose pre-construction period
under its licence had already expired and who had not applied to EMRA for issuance
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of a preliminary licence within the one-month time frame, also forfeits its generation
licence and the performance bond it had provided to EMRA. Any generation licence
or autoproducer licence applicant who wishes to withdraw its application within one
month of the effective date of the Draft EML may do so without risking its performance
bond since EMRA will return it to the applicant.
Market operation activities
Article 11 of the Draft EML introduces a new market activity called the ‘market operation
activity’. It is defined as an ‘operation of organised wholesale markets and financial
settlement of the activities realised in such markets’. This activity will be carried out by
the Enerji Piyasalari İşletme A.Ş. (‘EPİAŞ’) under its market operation licence, which
will be issued by EMRA. This activity will be transferred from Piyasa Mali Uzlaştirma
Merkezi (‘PMUM’) to EPİAŞ. Paragraph 4 of Article 11 sets out the basic duties of
EPİAŞ, which are in essence to operate as a market operator.
Share and facility transfers
Under the Current EML and the Licensing Regulation, EMRA approval is required
prior to the share transfer of 10 per cent (5 per cent for listed companies) or more of the
shares of the licence holder, an amendment to the articles of association of the licence
holder, or a transfer of the generation facility. The Draft EML abolishes EMRA approval
requirement for these transactions and instead requires ‘notification’. As per Article 5 of
the Draft EML, the licence holder will be obliged to notify EMRA of a share transfer
of 10 per cent (5 per cent for listed companies) or more of the shares of the licence
holder, changes in the control of the licence holder and any transaction resulting in
a change in the ownership of the generation facilities; however, licence holders whose
tariffs are subject to EMRA regulation will continue to be subject to the ‘prior approval’
requirement for a share transfer of 10 per cent (5 per cent for listed companies) or more
of its shares.
Distribution companies
It appears that when devising the Draft EML, the Ministry paid special attention to
distribution companies as the Draft EML introduces the following substantial changes
to distribution activities.
Appointment of an independent board member
The Draft EML provides that an independent board member must be appointed to the
board of directors of the licence holders whose tariff is subject to the EMRA regulation.
Generation companies’ shareholding restriction
Under the Current EML, generation companies may not take the control over distribution
companies. This restriction has been removed with the Draft EML.
Distribution companies’ shareholding restriction
Article 9 of the Draft EML prohibits distribution companies from involving any activity
other than distribution activities. Under the same provision, distribution companies will
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also not be allowed to be direct or indirect shareholders of a company engaged in other
market activities.
Safeguards and sanctions
Due to the nature of distribution companies, the Draft EML envisages additional
sanctions for them. According to the new regime, a distribution licence cannot be
cancelled. If the distribution company fails to fulfil its obligations with respect to its
distribution activities under applicable laws and regulations, commits certain breaches
that bring its distribution service quality to an unacceptable level, or becomes or will
become insolvent, EMRA may jointly or severally impose the following sanctions:
a all or some of the members of the board of directors will be dismissed and new
appointments will be made by EMRA accordingly;
b if the distribution licence holder fails to fulfil its investment and service obligations
under the tariff, the financial burden for such failure will be reimbursed from the
revenues extracted by the licence holder from other activities; if this is insufficient,
it will come out of dividends of the shareholders, and, if this is insufficient, from
other assets of the shareholders; or
c the seizure and transfer of the shares to the state, and the subsequent transfer of
the distribution licence to a third party will be carried out pursuant to Article 31
of the Draft EML.
Market share
The total volume of the electricity distributed by the same group of licence holding
companies may not exceed 30 per cent of the total electricity distributed in all regions
in the previous year.
Price equalisation mechanism
The deadline for the application of the price equalisation mechanism will be extended
until 31 December 2015.
Privatisation of generation facilities
The Draft EML grants a grace period to corporations that will be formed within the scope
of the privatisations of the generation facilities of EÜAŞ, its affiliates and subsidiaries, for
the realisation of all the investments that need to be made for environmental compliance
and completing environmental permit requirements. The grace period will expire on 31
December 2018. The Draft EML further provides that no penalties will be applicable for
pre-privatisation period.
Measurement requirement for wind and solar licence applications
The measurement report covering at least a period of one year must be provided for wind
and solar projects licence applications. This report must be prepared by a pre-approved
company and should not be older than three years.
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Tax exemptions and grants
Infrastructure construction charge
Distribution companies will be exempt from infrastructure construction charges for
their infrastructure works.
Privatisation exemptions
The Draft EML extends the deadline for corporate tax and VAT exemptions applied
to the earnings arising out of a transfer, merger, spin-off or partial spin-off realised
within the scope of the privatisations of distribution companies and generation asset or
companies. The deadline is extended from 31 December 2010 to 31 December 2017.
Stamp duty
The organised wholesale market transactions realised under the market operation licence
will be exempt from stamp duty. A stamp duty exemption is also granted to those
generation facilities that will be commissioned by 31 December 2015. The deadline
for this exemption is 31 December 2012 under the current EML. Water utilisation
agreements that do not contain joint facility investment amounts and were executed
after 26 June 2003 will continue to be exempt from stamp duty.
Discount on transmission system usage fee
A 50 per cent discount will be applied for the duration of five years to the transmission
system usage fee of the plants that will be commissioned by 31 December 2015. In the
current EML, the discount is applicable for the plants that will be commissioned by 31
December 2012.
VII
CONCLUSIONS and outlook
Turkey has shown that it is committed to promoting a robust private investment regime
for its electricity market. It has passed a great deal of progressive legislation, created road
maps to address its population’s growth and energy consumption, and is considering
making further amendments to the EML to promote competition and transparency
in the market. The government is implementing these changes so that it may provide
its population with a stable, efficient, clean and secure source of energy. By making
its market more competitive and transparent, the government also hopes that this will
in turn attract more private investment and increase domestic production of materials
associated with such investments. Furthermore, Turkey has been making efforts to
promote the development of its renewable energy sector to meet its population’s growing
demand for energy rather than relying more on foreign import of energy.
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Chapter 25
United Arab Emirates
Masood Afridi and Haroon Baryalay 1
I
OVERVIEW
The United Arab Emirates (‘the UAE’) is a federation of the seven emirates of Abu
Dhabi, Ajman, Dubai, Fujairah, Ras al-Khaimah, Sharjah and Umm al-Quwain. The
seat of the federal government is situated in Abu Dhabi, which is the largest emirate
by area (making up about 85 per cent of the country’s area) and the richest in terms
of oil resources. Dubai is the second-largest emirate by size. Together, Dubai and Abu
Dhabi account for about two-thirds of the country’s population and form the core of its
economy.
The UAE’s economy has traditionally been dominated by the petroleum industry
but successful efforts at economic diversification have reduced the share of the oil and
gas sector in the country’s GDP to 25 per cent. The UAE has an open economy with
one of the highest per capita incomes in the world and a sizeable annual trade surplus.
The currency is freely convertible and funds are freely repatriable. The country’s free
zones – offering 100 per cent foreign ownership and zero taxes – are a major conduit for
foreign investment in the country. The geographical location of the UAE, situated at the
tip of the Arabian Peninsula, has made it a convenient trading post between the gulf and
Asia. With modern communication, the UAE remains a convenient trading base for the
Indian sub-continent, central Asia, Africa and beyond.
The powers of the federal and the emirate governments are enumerated in the
State Constitution of 1971. Although the country is a federation, the larger emirates
largely pursue their own economic policies. Article 120 of the UAE Constitution gives
the federal government exclusive legislative and executive jurisdiction over electricity
services, but in practice the emirates formulate and implement their own electricity
policies and operate independently of each other. Hence, although there is a Federal
1 Masood Afridi is a partner and Haroon Baryalay is an associate at Afridi & Angell.
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Ministry of Energy (which formulates and implements the federal electricity policies),
Federal legislation on electricity is somewhat limited.
Due to the significance of Abu Dhabi and Dubai within the Federation, this
chapter focuses primarily on the electricity sector in these emirates, and also touches on
the federal laws and policies relating to the electricity sector.
The generation, transmission and distribution of electricity in the UAE is
dominated by three water and power authorities owned by each of the individual emirates
of Dubai, Abu Dhabi and Sharjah, and by a federal authority that operates in the smaller
northern emirates. These state-owned authorities serve as the exclusive purchasers of
electricity and distributors in each of their areas of operation. Whereas the private sector
is allowed to participate in the generation of electricity, transmission and distribution is
exclusively owned by state-owned authorities.
Abu Dhabi is the only emirate that has a number of private sector participants
owning up to a 40 per cent economic interest in various electricity generation plants in
the emirate. Dubai has recently enacted legislation to enable private sector participation
in the power generation sector. A privatisation policy has also been announced by the
federal government for the northern emirates.
So far, only Dubai and Abu Dhabi have enacted laws creating specialised
regulatory bodies for the electricity sector. These consist of the Supreme Energy Council
(‘the SEC’) and the Electricity and Water Sector Regulation and Control Office (‘the
Office’) in Dubai, and the Electricity Regulation and Supervision Bureau in Abu Dhabi
(‘the Bureau’). The Federal Ministry of Energy regulates the sector at the federal level and
works in conjunction with the Federal Electricity and Water Authority (‘FEWA’), for the
implementation of the federal government’s electricity policy in the northern emirates.
Increasing population growth and urban development has been responsible for
electricity demand in the UAE to grow at double-digit rates, and demand is expected to
continue to grow at over 10 per cent annually in the foreseeable future. There is currently
insufficient power generation capacity in some parts of the UAE, and demand is being
met by selling power between the emirates through the Emirates National Grid (‘the
ENG’). Some industrial projects have not been able to secure sufficient power supply and
have had to resort to captive power generation.
A number of major power projects, both in the field of conventional and
renewable energy, are under development to help meet the country’s existing and future
electricity needs.
II
REGULATION
i The regulators
Federal
The UAE’s Federal Ministry of Energy, the primary regulator at the federal level, was
formed pursuant to Federal Decree No. (3) of 2004 (‘the Ministry of Energy Decree’)
by merging the Ministry of Petroleum and Mineral Resources with the Ministry of
Electricity and Water. FEWA, which was established pursuant to Federal Law No. 31
of 1999 (‘the FEWA Law’), as amended by Federal Law No. 9 of 2008, is the dominant
player in the market.
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The Ministry is responsible for formulating the federal government’s policy on
energy, including electricity. It has announced a strategic energy plan to develop the
federal government’s electricity services by attracting private investment in the sector.
The Ministry of Energy also represents the country in the international petroleum
community and specialised international and regional organisations. 2
Abu Dhabi
In Abu Dhabi, Law No. (2) of 1998 Concerning the Regulation of Water and Electricity
Sector (‘Abu Dhabi Electricity Law’), as subsequently amended by Law No. (19) of 2007
and Law No.(12) of 2009 is the foremost legislation governing the electricity sector
in the emirate. The sole and exclusive regulator is the Bureau and the main electricity
company is the Abu Dhabi Water and Electricity Authority (‘ADWEA’), both of which
are established under the Abu Dhabi Electricity Law.
The Bureau’s authority includes the power to:
a issue licences to conduct regulated activities;
b
c
monitor licensees and ensure compliance with terms of licences issued; and
make regulations as it sees fit for the regular, efficient and safe supply of electricity
in the emirate.
Dubai
The Dubai Electricity Law, the DEWA Law, SEC Law and the Dubai Office Resolution
(each defined below) are the primary laws regulating the electricity sector in Dubai.
The apex regulator is the SEC with the Office being the specialist regulatory authority.
The main player in the electricity market is the Dubai Electricity and Water Authority
(‘DEWA’).
Dubai’s SEC was established under Dubai’s Law No. (19) of 2009 (the ‘SEC
Law’). Member organisations of the SEC include DEWA, Dubai Aluminum Company
Ltd (DUBAL), Emirates National Oil Company, Dubai Supply Authority, Dubai
Petroleum Corp, Dubai Nuclear Energy Committee and Dubai Municipality.
The SEC is responsible for all initiatives relating to the energy sector 3 in Dubai,
including generation, transmission and distribution of electricity for public consumption.
The generation of electricity from renewable sources and nuclear energy is also subject to
the SEC’s regulatory oversight. The SEC is responsible for, inter alia:
a
b
coordinating the affairs of energy related entities within the emirate;
liaising with international and regional organisations and companies operating in
the energy sector; and
2 The UAE has been a member of the Organisation of Petroleum Exporting Countries (OPEC)
since 1974 and of the Organisation of Arab Petroleum Exporting Countries (OAPEC) since
1970.
3 As the primary regulator of the energy sector, the exploration, production, storage, transmission
and distribution of petroleum products (natural gas, liquid petroleum, petroleum gases, crude
oil) is also regulated by the SEC within Dubai.
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c
issuing decisions and by-laws to implement the provisions of Dubai’s Law No.(6)
of 2011 ‘Regulating the Participation of the Private Sector in Electricity and
Water Production in the Emirate of Dubai’ (‘the Dubai Electricity Law’).
The Office was established in 2010 pursuant to Dubai Executive Council’s Resolution
No.(2) of 2010 (‘Dubai Office Resolution’), and is authorised to regulate the electricity
sector in Dubai, subject to the overall supervision of the SEC. The Office is responsible,
inter alia, for:
a issuing electricity generation licences;
b proposing legislation governing the electricity sector in Dubai;
c determining and establishing standards and controls for electricity generation in
the emirate; and
d carrying out such other duties as the SEC may assign to it from time to time.
ii Regulated activities
Abu Dhabi
Under the Abu Dhabi Electricity Law, regulated activities include electricity generation,
transmission, distribution and supply to premises. Any person or entity intending to
carry out these activities is required to be licensed by the Bureau.
Dubai
Under the Dubai Electricity Law, regulated activities include ‘any activity related to
generating electricity […] for the purpose of supplying to the Transmission System
with produced electricity’. The transmission system is defined as high voltage electricity
cables and electricity installations and facilities owned or operated by DEWA and used
to transmit electricity. All activities relating to electricity generation, transmission,
distribution and supply of electricity are regulated activities under the Dubai Electricity
Law and require a licence from the Office.
iii Ownership and market access restrictions
Under the UAE’s Commercial Companies Law 1984 (‘the Companies Law’), 4 foreigners
may only own up to 49 per cent of any onshore UAE company. Therefore, as with
all onshore entities, all power sector companies established within the UAE must be
majority owned by local nationals, whether privately or by the government. So far, the
local ownership share has mostly been taken up by the government-owned water and
electricity authorities in the various emirates.
Although the UAE free zones allow for 100 per cent foreign ownership, the free
zone companies are not allowed to transact business within the UAE (they are restricted
to operating in the free zone itself or outside the UAE) and would not be able to supply
electricity to the mainland.
The UAE’s electricity laws do not impose any specific ownership restrictions on
foreign investors in the UAE, nor do they necessarily require government participation
4 Federal Law No.(8) of 1984, as amended.
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in the electricity sector. However, as a matter of policy, most companies are either wholly
or majority owned by the federal or respective emirates’ governments and the sector is
dominated by the state-owned water and electricity authorities. Of these, the Dubai
and Abu Dhabi authorities, being the largest two, account for about 85 per cent of
the UAE’s entire production capacity. ADWEA accounts for approximately 52 per cent
of the UAE’s entire power generation capacity (12,800MW), DEWA for 33 per cent
(8,700MW), SEWA for 10 per cent (2,400MW) and FEWA, which operates in the
northern emirates, for about 5 per cent (1,150MW).
Abu Dhabi
ADWEA was established pursuant to the Abu Dhabi Electricity Law, and it is responsible
for all matters relating to formulation, development and implementation of policy of the
Abu Dhabi government in relation to the electricity sector, including the privatisation
of the electricity sector. ADWEA is managed by a board and headed by a chairman,
appointed by Royal decree (Emiri decree). In addition to managing the public sector
entities, ADWEA can also establish joint ventures with private sector companies.
ADWEA is the owner of the Abu Dhabi Power Corporation (‘ADPC’), a holding
company established to own shares in operating-level companies that generate, transmit
and distribute water and electricity in the emirate. 5 ADPC in turn owns the Abu Dhabi
Water and Electricity Company (‘ADWEC’), the single buyer of water and electricity in
Abu Dhabi, and the Abu Dhabi Transmission and Dispatch Company (‘TRANSCO’),
the main transmission company in the emirate.
ADWEA has established a long-term programme for the privatisation of the
electricity sector. To date, a number of independent water and power producers (‘IWPPs’)
have been established as joint-venture arrangements between ADWEA and various
international power companies as BOO (build–operate–own) projects. In accordance
with long-term arrangements, IWPPs are committed to selling their production to
ADWEC.
The major IWPPs include:
a Al Mirfa Power Company;
b Arabian Power Company;
c Emirates CMS Power Company;
d Emirates SembCorp Water and Power Company;
e Fujairah Asia Power Company;
f Gulf Total Tractebel Power Company;
g Ruwais Power Company;
5 Under the Abu Dhabi Electricity Law, ADPC was established with the following subsidiaries:
(1) Abu Dhabi Water and Electricity Company (ADWEC); (2) Abu Dhabi Transmission and
Dispatch Company (TRANSCO); (3) Al Taweelah Power Company; (4) Al Mirfa Power
Company; (5) Umm Al Nar Power Company; (6) Bainounah Power Company; (7) Abu
Dhabi Distribution Company (ADDC); (8) Al Ain Distribution Company (AADC); (9) Abu
Dhabi Company for Servicing Remote Areas (RASCO); (10) Al Wathba Company for Central
Services; (11) Industrial Security Company; and (12) Central Workshop Company.
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h
i
j
k
l
Shams Power Company PJSC;
Shuweihat Asia Power Company PJSC;
Shuweihat CMS International Power Company;
Umm Al Nar Power Company; and
Taweelah Asia Power Company.
The ownership of the IWPPs is split 60:40 between ADWEA (or its subsidiaries) and the
foreign investor. The project companies are usually structured as joint stock companies
incorporated in Abu Dhabi. The most common ownership structure is one in which
ADWEA incorporates an intermediate holding company to own a 60 per cent stake,
which is in turn held 10 per cent by ADWEA and 90 per cent by the Abu Dhabi
National Energy Company PJSC (also known as TAQA). 6 A few project companies have
other ownership structures.
Dubai
DEWA was established under Dubai’s Law No.(1) of 1992 (‘DEWA Law’) as an
independent public authority owned by the government of Dubai. DEWA is managed
by a board of directors whose members are appointed by Emiri decree.
DEWA is an integrated supplier owning and operating in all segments of the
electricity market in Dubai. Although the Dubai government wants to promote private
investment in its electricity generation sector, to date, all of the power generation capacity
of Dubai, except for captive power produced by certain entities (e.g., DUBAL), is owned
by DEWA.
Dubai has only recently passed legislation allowing the private sector to participate
in electricity generation. The Dubai Electricity Law is broadly modelled on the Abu
Dhabi Electricity Law. The Dubai Electricity Law authorises DEWA to establish project
companies, by itself or in collaboration with third parties, for the generation of electricity.
So far, DEWA had solicited bids for the Al Hassyan 1 Independent Power Project,
a 1,600MW gas-fired power plant, in December 2011 but has since deferred the project.
DEWA proposes to retain a 51 per cent ownership share in the project. Al Hassyan 1 is
the first of six planned IWPPs in Dubai forming part of a power and water complex with
total capacity of 9,000MW.
Northern emirates
FEWA is responsible for the generation and distribution of electricity in the northern
emirates of Ajman, Ras al-Khaimah, Fujairah and Umm al-Quwain. FEWA is governed
by a board of directors whose members hold office for a term of three years.
6 Delmon, Jeffery and Delmon, Victoria Rigby, International Project Finance and PPPs – A Guide
to Key Growth Markets 2012, Chapter 16, p. 26 (2012). TAQA, in which ADWEA owns a 51
per cent ownership stake, was established under Abu Dhabi Decree No.(16) of 2005 and serves
as ADWEA’s investment arm in the emirate and abroad.
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FEWA is authorised under the FEWA Law to establish private power generation
plants in the northern emirates. A number of such projects have been developed or are
presently under development in these emirates.
FEWA acts as the single point of sale for all power generated in the northern
emirates. Electricity transmission and distribution networks within the northern emirates
are owned and operated by FEWA.
Sharjah
Sharjah has its own electricity authority known as the Sharjah Electricity and Water
Authority (‘SEWA’) (established pursuant to Sharjah Emiri Decree No. 1 of 1995, as
amended by Emiri Decrees No. 46 of 2006 and No. 20 of 2008), which is authorised
to ‘own–manage–operate–maintain’ power stations and electricity transmission lines.
Within the emirate, SEWA is responsible for the generation, transmission and distribution
of electricity. SEWA is authorised to determine electricity prices and connection fees,
which are subject to approval by the Ruler of Sharjah.
iv Transfers of control and assignments
Abu Dhabi
Under the Abu Dhabi Electricity Law, a licence may not be transferred unless it specifically
permits its transfer. Prior consent of the Bureau is required for any transfer (including
the creation of security over assets of the licence holder), which consent may be subject
to such conditions as the Bureau may consider appropriate.
Dubai
Under the Dubai Electricity Law, licensed entities are not permitted to transfer or assign
their licences without the prior approval of the Office. In addition, licensed entities
may not dispose off, sell, lease or otherwise transfer, including granting of a security
interest over, their ‘main assets’ without prior approval from the Office. Main assets are
those moveable and immoveable assets necessary to conduct the regulated activities and
operate the electricity generation facilities.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
As noted above, electricity transmission and distribution in the UAE is controlled by
the state-owned water and power authorities, each of which enjoys a monopoly in its
particular area of operation.
Abu Dhabi
ADWEA’s wholly owned subsidiary TRANSCO operates Abu Dhabi’s transmission
networks. TRANSCO supplies electricity from the generating companies to the two
distribution companies of Abu Dhabi (discussed below). Recently, TRANSCO has also
become involved in the planning, development and operation of electricity transmission
networks in the northern emirates.
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Abu Dhabi is serviced by two electricity distribution companies each of which are
wholly owned by ADWEA. These are:
a the Abu Dhabi Distribution Company (‘the ADDC’), which operates in the city
of Abu Dhabi and the areas known as the ‘western region’ of the emirate.
b the Al Ain Distribution Company (‘the AADC’), which operates in Al Ain city
and the surrounding areas.
Dubai
DEWA is the sole purchaser of electricity in Dubai and presently owns all the generation,
transmission and distribution capacity of the emirate. 7 DEWA’s transmission and
distribution network is constantly being expanded as new real estate and industrial
projects are set up across Dubai.
Emirates National Grid
The ENG project was launched in the year 2000 to connect and enable sharing of power
between the UAE’s seven emirates. The ENG project was launched by the Ministry of
Energy with the purpose of enhancing integration between the various electricity and
water authorities in the UAE, each of which contributed proportionately to the capital
investment required to build the ENG. The ENG is owned by the following authorities
in the proportions stated below:
a ADWEA: 40 per cent;
b DEWA: 30 per cent;
c FEWAL 20 per cent;
d SEWA: 10 per cent.
Dubai and Abu Dhabi’s power grids were connected by the ENG in the middle of 2006,
whereas SEWA’s connection to ENG was completed in May 2007. Connection to the
remaining northern emirates transmission networks was completed in April 2008.
Due to its larger production capacity and extensive distribution network,
ADWEA has increasingly been assisting the other emirates in meeting their power
demand. According to the Bureau, Abu Dhabi exported about 1,900MW of electricity
to other emirates via the ENG in 2011.
The GCC Grid
The UAE is also connected to the rest of the GCC through the GCC Grid, through
which it can trade electricity with the remaining GCC countries. About 56MW of
electricity was exported by Abu Dhabi to the GCC Grid in 2011.
7 DEWA operates a network of overhead lines (875 kilometres of 400kV, 437 kilometres of
132kV and 113 kilometres of 33kV lines) and underground cables (1,250 kilometres of 400kV,
1,985 kilometres of 33kV and 23,987 kilometres of 6.6 and 11kV lines) that are, in turn,
connected to a distribution system of lower voltage substations and distribution lines.
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ii
United Arab Emirates
Transmission/transportation and distribution access
Abu Dhabi
The Abu Dhabi Electricity Law requires ADWEC to purchase all power produced within
the emirate. Although the Abu Dhabi Electricity Law contemplates private ownership
in all segments of the electricity supply chain, so far private ownership has been limited
to generation only.
Dubai
The Dubai Electricity Law prohibits a licensed entity from selling electricity to any entity
other than DEWA.
iii Rates
Abu Dhabi
ADWEC, being the only buyer of electricity in the emirate of Abu Dhabi, purchases
electricity from the power producers under long-term power and water purchase
agreements (‘PWPAs’) and sells it to the distribution companies via annual bulk supply
tariff (‘BST’) agreements. The distribution companies pay ADWEC the BST for the
electricity purchased and receive revenue from their customers and a subsidy from the
government. TRANSCO is paid a transmission use of system (‘TUoS’) charge by the
distribution companies.
The components making up the electricity tariff in Abu Dhabi are the following:
a BST, which is the charge paid by the distribution companies to ADWEC for its
generation costs (in turn paid by ADWEC to power producers).
b TUoS, which is the charge paid by the distribution companies to TRANSCO for
use of its transmission network.
c Distribution use of system (DUoS), which is the fee that the distribution
companies charge for use of their distribution network.
d Sales cost, or the cost incurred by the distribution companies for serving customers
for meter reading and billing.
e Government subsidy, consisting of direct payments from the government to the
distribution companies. The quantum of the subsidy allows the government to
determine the electricity tariffs for different classes of consumers. The higher the
subsidy, the lower the tariff charged.
The electricity tariff is determined by adding components (a) to (d) and subtracting (e).
The rates charged by the state-owned power companies (ADWEC, TRANSCO,
ADDC, AADC and RASCO) are subject to government control, which is exercised
through the Bureau. The Bureau sets their revenue target on the basis of which the
control prices are then determined. The remainder of the revenue is paid as a subsidy by
the government to the distribution companies. All transactions between the power sector
companies and any related tariffs are required to take place on the basis of their economic
costs. This helps the government keep subsidies to a minimum.
The BST is calculated for each calendar year on the basis of parameters prescribed
by the Bureau.
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The calculation of BST requires the estimation of the costs for procuring and
dispatching electricity generation to meet the forecasted demand. Starting 2012, the
structure of the BST comprises three components (expressed in fils/kWh) charged on
an hourly basis for electricity purchased at different times of the day, for ‘Fridays’ and
‘non-Fridays’ and in different months of the calendar year. These three components are:
a a ‘system marginal price (SMP) charge’ estimated to indicate the short-term
marginal costs (excluding back-up fuel (‘BUF’) costs) of providing units at
different times of the day;
b a ‘BUF levy charge’ estimated to reflect the additional costs associated with the
burning of back-up fuel rather than primary fuel; and
c a ‘high-peak period charge’ assessed to cover the costs associated with the estimated
capacity payments and charged only in the peak demand occurring months of
June to September, inclusive.
The TUoS charge paid to TRANSCO covers the investment, operation and maintenance
costs of the infrastructure of the transmission systems, excluding assets that are dedicated
entirely to a particular customer. These include substations, overhead lines, cables and
associated equipment. TUoS charges also cover the costs of the economic scheduling and
dispatching of electricity generation.
For the power generation companies, their rates are determined on the basis of
the PWPAs entered by them with ADWEC. These PWPAs are further discussed below.
Contracts for power generation are awarded based on a competitive bidding process
after the government invites tenders to meet the emirate’s power generation requirements.
The bidding process is managed by ADWEA starting from pre-qualification of bidders
and issuance of request for proposals (RFPs) through to selection of the successful bidder.
Electricity rates paid by consumers in Abu Dhabi are subsidised. In fact, UAE
nationals benefit from even greater subsidies than those given to expatriate workers.
The rates payable in Abu Dhabi as published by the Bureau on its website are divided
according to consumer categories as follows:
a UAE nationals – domestic (remote areas): 3 fils per kWh
b UAE nationals – domestic (other areas): 5 fils per kWh
c Non-UAE nationals – domestic: 15 fils per kWh
d Industrial/commercial: 15 fils per kWh
e Governmental and schools: 15 fils per kWh
f Farms: 3 fils per kWh
According to news reports quoting electricity officials in Abu Dhabi, the government
subsidy for water and electricity services in Abu Dhabi accounts for nearly 86 per cent of
the cost of a unit of electricity for nationals and 50 per cent for expatriates.
Dubai
Under the DEWA Law, the board of directors of DEWA are given the power to control
electricity prices charged by DEWA, subject to the Ruler’s approval; however, since the
promulgation of the SEC Law, the electricity prices have been determined by the SEC
and DEWA now sets its prices in accordance with the SEC’s directives. The SEC Law
empowers the SEC to impose a ‘definite tariff based on cost when necessary’. The SEC
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is also authorised to approve fees and tariffs on the services offered to the public by
‘energy service providers’ (meaning the power generation, transmission and distribution
companies).
The electricity tariff in Dubai comprises of the electricity consumption charges,
the fuel surcharge and meter charge. Electricity tariffs in the emirate are based on a slab
tariff scheme whereby higher consumption attracts a higher slab rate.
DEWA has (since 1 January 2011) increased electricity rates and under directions
from the SEC, introduced a variable fuel surcharge in its electricity tariff. The fuel
surcharge component requires consumers to pay for any fuel cost increases, using 2010
fuel prices as the benchmark, thereby passing on the risk of international fuel price
fluctuations onto consumers. This has enabled the company to increase revenues, reduce
demand growth and earn higher profits.
As with Abu Dhabi, power projects in Dubai are proposed to be awarded on the
basis of a competitive bidding process. DEWA is responsible for managing the bidding
process in the emirate (bids for the Al Hassyan project were solicited through DEWA).
IWPPs that are established in the emirate will need to enter into PWPAs with DEWA
for the sale of their production.
IV
ENERGY MARKETS
i Development of energy markets
The electricity market for private power producers in the UAE is comprised of the stateowned
water and power authorities each of which act as the single point of sale in their
respective areas of operation.
Contracts for power generation are awarded on the basis of a competitive bidding
process, administered by ADWEA in Abu Dhabi, DEWA in Dubai and FEWA in the
northern emirates.
A number of renewable energy initiatives (discussed below) have also been
launched.
ii Energy market rules and regulation
Under the Abu Dhabi Electricity Law, ADWEC is required to contract with power
producers for the purchase of all production capacity from licensed operators in the
emirate. ADWEA is authorised to allow ‘by-pass sales’ from power producers directly to
eligible consumers provided that:
a the first independent commercial power generation project in the emirates shall
have commenced commercial operations;
b the majority of the shares in such company are privately owned; and
c the Bureau issues a report stating that the energy market in the country is stable
enough for it to be in the public interest that the sale of electricity by producers
to eligible consumers be permitted.
To date, no ‘by-pass sales’ of electricity have been allowed by ADWEA in Abu Dhabi and
all existing producers in the emirate are required to sell their production to ADWEC.
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Similarly, power producers in Dubai are obligated by law to sell their entire
production capacity to DEWA. All power generation companies in the northern emirates
and Sharjah must also sell their power production to FEWA or SEWA respectively.
iii Contracts for sale of energy
Abu Dhabi
ADWEC pays the generation companies the tariff agreed under the PWPAs. The PWPA
serves both as a grant of concession and offtake agreement. 8
The PWPAs usually have a term of about 20 to 25 years from the commencement
of commercial operations. Payments to IWPPs by ADWEC under PWPAs comprise
three main components:
a capacity (or availability) payments covering the fixed costs of the plant (return on
capital, depreciation and fixed operating and maintenance costs);
b operation and maintenance costs, paid when plant is available for production
irrespective of whether and how much the plant produces; and
c output (or energy) payments for variable operation and maintenance costs,
payable only for the electricity actually produced by the plant and despatched.
The primary fuel used in the power generation sector in the UAE is natural gas, accounting
for 90 per cent of all production. As is often the case in such models, fuel costs are
pass-through, and ADWEC is required to procure and supply fuel to the electricity
producers under the Abu Dhabi Electricity Law. ADWEC acquires the natural gas from
two sources, the Abu Dhabi National Oil Company (ADNOC) and Dolphin Energy
Limited (purchased from Qatar via a pipeline connecting both states) for onward supply
to the power producers.
Power plants are required to stock diesel oil and crude oil as back-up fuel.
According to the standard PWPAs, generation companies have to stock up enough backup
fuel for their plants to run at full capacity for seven days.
PWPA payment rates under some of the agreements are subject to annual
indexation against US and UAE inflation or the $/dirham exchange rate (the UAE’s
currency is pegged to the US dollar at a fixed exchange rate of $1 to 3.67 dirhams).
ADWEC is required by the standard PWPAs to pay certain other supplemental
payments to the IWPPs, such as start-up, shut-down costs and back-up fuel costs. Some
PWPAs may also have provisions for payment by the relevant party of liquidated damages
for delay in performance and of interest on late payments.
Dubai
Dubai does not have a standard power purchase agreements in place as yet. DEWA’s first
proposed joint venture with the private sector, Al Hassyan 1, is still in the bidding phase.
Any agreements entered with IWPPs in Dubai are likely to be modeled on the existing
PWPAs signed by ADWEC.
8 Delmon, Jeffery and Delmon, Victoria Rigby, International Project Finance and PPPs – A Guide
to Key Growth Markets 2012 p. 26 (2012).
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iv
Market developments
United Arab Emirates
The UAE proposes to develop renewable energy sources to reduce its dependence
on carbon fuels. A number of renewable energy projects have been launched in this
connection (please see below for details).
In addition, the UAE has begun construction on its first nuclear energy power
plant. It has developed a regulatory framework for the sector and plans to use nuclear
energy to meet a substantial portion of its energy needs. This is discussed in further detail
below.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
High energy use, encouraged by subsidised energy prices and the construction of energy
intensive industries (such as aluminium smelting), has resulted in the UAE having one
of the highest per capita carbon footprints in the world. The development of renewable
energy is therefore crucial in reducing the country’s carbon footprint. The UAE has
announced that it aims to produce 7 per cent of electricity from renewable sources by
2020.
A number of showcase projects have been launched in Abu Dhabi and Dubai to
kickstart the development of renewable energy in the country.
Abu Dhabi
Abu Dhabi has established the Abu Dhabi Future Energy Company (‘ADFEC’) 9 to
spearhead the emirate’s renewable energy initiative. Masdar City, a project launched by
ADFEC to be constructed in the outskirts of Abu Dhabi City, is proposed to be run
entirely on renewable energy with zero carbon emissions. Masdar City has also won the
rights to host the headquarters of the International Renewable Energy Agency (IRENA).
ADFEC has launched a number of other renewable energy projects which include:
a production of up to 50MW of electricity at its solar photovoltaic power plant
located at the Masdar City for supply to the project;
b a 100MW Shams Solar Power Project (60 per cent owned by ADFEC), which is
expected to be completed by the end of 2012 in Madinat Zayed in Abu Dhabi;
c a wind turbine on Sir Bani Yas Island with a capacity of 850kW, which has already
been completed. In addition, ADFEC proposes to produce up to 40MW of
electricity employing the use of wind turbines;
d a 500MW integrated hydrogen power generation and desalination plant; and
e a carbon capture and storage project.
Dubai
In 2010 the SEC developed the Dubai Integrated Energy Strategy 2030, according to
which Dubai will diversify its energy sources so that by 2030 it can fulfil 5 per cent of
9 ADFEC is owned by Mubadala Development Company, the Abu Dhabi government’s
investment vehicle.
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its energy demand from solar energy, 12 per cent from nuclear energy, 12 per cent from
clean coal and 71 per cent from natural gas.
As part of this strategy, in January 2012, Shaikh Mohammad Bin Rashid Al
Maktoum, the Ruler of Dubai, launched a 12 billion dirhams solar power project,
known as the Mohammad Bin Rashid Al Maktoum Solar Park. This solar park will
ultimately have a capacity to generate 1,000MW of electricity from solar energy. The
project’s capacity is to be increased in phases with production of 1,000MW of electricity
expected to be completed by 2030. The project is being implemented by the SEC in
Dubai and is being managed and operated by DEWA.
Dubai has also established the Dubai Carbon Centre of Excellence (DCCE),
responsible for encouraging and developing strategies towards reducing the emirate’s
dependence on carbon fuels and reducing carbon emissions.
Dubai will also host the World Energy Forum in October 2012, and given that
2012 is the year designated by the United Nations as the International Year of Sustainable
Energy, it highlights the UAE’s commitment towards diversification away from fossil
fuels towards renewable energy.
Although the UAE’s recent steps towards developing more renewable energy
projects in the country are commendable, the projects launched so far will only fulfil
a small part of the country’s total energy requirements. Despite the announcement to
produce 7 per cent of the country’s total energy requirements from renewable sources by
2020, the UAE has not set itself a mandatory renewable energy target.
In order to encourage private investment in renewable energy, the government
would need to enact formal legislation to regulate the development of renewable energy.
A subsidy for renewable energy sources combined with a feed-in tariff that guarantees
that electricity generated from renewable sources will be purchased for a minimum price
can be introduced as a further incentive.
Nonetheless, recent initiatives in the field of renewable energy launched in
Dubai and Abu Dhabi along with creation of specialised entities to further develop the
renewable energy projects have made the UAE one of the most dynamic and exciting
markets for renewable energy in the region.
Nuclear energy
The UAE aims to produce a significant part of its electricity from nuclear technology.
The UAE released a nuclear policy in 2008 and has since then promulgated a regulatory
framework for development of nuclear energy in the country. In addition to collaborating
with the International Atomic Energy Agency (‘IAEA’) and the World Association of
Nuclear Operators, the UAE has signed cooperation agreements with Korea (2009),
the United States (2009), France (2008) and the United Kingdom (2008) for the
development of peaceful use of nuclear energy.
The Federal Authority for Nuclear Regulation (‘the FANR’), the federal nuclear
energy regulator headquartered in Abu Dhabi, was established in 2009 under Federal
Law No.(6) of 2009 Concerning the Peaceful Use of Nuclear Energy. The FANR is
tasked with the responsibility of setting up the procedures and measures to be followed
for the development of nuclear technology in the UAE. The FANR has issued regulations
governing, inter alia, licensing, site location, design, construction, commissioning and
operation, as well as standards for safety, transportation and storage facilities, radioactive
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waste management and physical protection of nuclear materials. The UAE has also created
the International Advisory Board (‘IAB’), an independent body consisting of independent
international experts on nuclear energy who will offer guidance to the country’s nuclear
program on compliance with international safety, security and proliferation standards.
The IAB is presently chaired by Hans Blix, the former IAEA Director General.
The UAE has been making rapid strides in establishing its first nuclear power
station. The Emirates Nuclear Energy Corporation (‘ENEC’), an Abu Dhabi government
owned company established by Federal Law No.(21) of 2009, is constructing the Braka
nuclear power plant in Abu Dhabi (with a capacity of 5,600MW), which is expected
to be completed in phases commencing in 2017 until 2020. Braka is the first of four
nuclear plants planned to be constructed in the country.
ii Energy efficiency and conservation
In 2010, Abu Dhabi imposed a mandatory rating system for construction of energyefficient
buildings in the emirate under the Estidama initiative. Starting from September
2010, all new development communities, private buildings and villas in the emirate are
required to meet the minimum of one-pearl rating. All government led projects have
been mandated to meet a two-pearl rating (the highest being a five-pearl rating).
The Dubai government has also enacted the Green Buildings Regulations to
encourage sustainable building practices. These regulations are enforced by the Dubai
Municipality and apply to all new buildings constructed (including changes or additions
to existing buildings) in the emirate.
In order to attract foreign private investment in the sector, Dubai has created a
free zone dedicated towards development of green technologies and energy conservation
known as the Energy and Environment Park (‘EnPark’). EnPark is also Dubai’s first
master-planned community built on sustainable principles.
Through recent investment in its transmission system, DEWA succeeded in
reducing the percentage of line losses in its electrical network to 3.49 per cent in 2011
from 6.28 per cent in 2001. As part of its demand growth management strategy, DEWA
has introduced a slab tariff that has been successful in reducing demand growth to 3 per
cent despite a 5 per cent growth in end users in 2011. FEWA also has a slab tariff in
place for the northern emirates whereas ADWEA is proposing to launch a similar tariff
structure in the near future.
iii Technological developments
AFDEC has established the Masdar Institute of Science and Technology (‘MIST’), a stateof-the-art
research centre and university, in partnership with Massachusetts Institute of
Technology. MIST is a graduate-level university that aims to provide solutions to issues
of sustainability, focusing on advanced energy and sustainable technologies, through
research.
Although it is a brand new institute, according to its website, over 30 research
projects are currently underway, covering solar beamdown, innovation ecosystems,
smartgrids and aviation biofuels. In addition, according to its website, a number of
patents are already pending registration.
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MIST is likely to play a leading role in development of advanced technologies in
the UAE in the coming years.
VI
THE YEAR IN REVIEW
The UAE has seen double-digit increase in the demand for electricity in the past few
years and is expected to continue seeing rapid growth in the coming years.
In order to meet this growing demand, Abu Dhabi has allowed private power
companies to participate in its energy sector for a number of years. More recently, due to
the rapid growth in demand for power in the country, Dubai and the federal government
have both launched initiatives to permit private sector participation in the generation of
electricity. Dubai enacted the Dubai Electricity Law and the FEWA Law was amended in
2008 to enable private investment in the sector. Transmission and distribution continues
to be owned by the state owned monopolies.
The need for specialised regulation is recognised and Dubai has enacted a number
of laws to modernise its regulatory framework. Two specialist regulators for the energy
sector, the SEC and the Office, have been established, with the latter focusing primarily
on electricity. The enactment of the Dubai Electricity Law can be directly attributed to
the creation of these specialist regulatory bodies.
High subsidies and heavy reliance on fossil fuels for generation have resulted in
the UAE having one of the highest per capita carbon footprints in the world. Rising fuel
prices have created a growing recognition that the energy demand cannot be met only
with investment on the supply side but that demand-side management programmes and
energy conservation measures are equally important in matching demand with supply.
Increases in electricity tariffs coupled with the introduction of slab tariffs in Dubai and
the northern emirates have helped curb demand growth in these areas and relieved
pressure on the sector. Due to the effectiveness of the slab tariff introduced by DEWA,
Abu Dhabi is also proposing to introduce a slab tariff in the near future.
Green building regulations and a mandatory rating scheme have been introduced
in Dubai and Abu Dhabi respectively to encourage energy conservation.
The country has set itself the goal of ensuring 7 per cent of its energy requirements
in 2020 are met from renewable sources. Dubai has set itself a target of generating about
one-third of its energy from clean, renewable or nuclear sources by 2030. To meet these
targets, a number of projects have been launched.
Dubai has recently inaugurated a solar energy park which will, on completion in
2030, have the capacity to produce 1,000MW of electricity.
Abu Dhabi has launched the zero carbon emissions/zero waste Masdar City
project to be powered exclusively by renewable energy sources. ADFEC, the owner of
the project, has started work on development of a number of renewable energy projects,
including solar and wind.
A specialist regulatory body for the nuclear energy sector has been created. New
regulations governing various segments of the nuclear chain are being developed and
issued. Construction work on a nuclear power plant is currently underway at Braka in
the emirate of Abu Dhabi, and commissioning is expected in 2017.
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VII
CONCLUSIONS and OUTLOOK
As seen above, in addition to the drive towards privatisation, notable developments
towards energy diversification and introduction of renewable sources have taken place.
These developments, however, remain restricted to the government sector and more
needs to be done to encourage private sector participation both in conventional and
renewable energy.
The state-owned monopolies in the various emirates are likely to continue to
dominate the sector in the foreseeable future. The requirement under the Companies
Law to maintain majority ownership in local hands means that foreign private investors
will have to work with the local water and power authorities as junior partners.
Although Abu Dhabi has seen foreign investment in the sector for a number
of years, the other emirates such as Dubai and the northern emirates remain relatively
inexperienced. The other emirates are likely to follow the example set by Abu Dhabi and
implement similar ownership structures and model agreements. The PWPAs, operations
and maintenance contracts and engineering, procurement and construction agreements
and government guarantees are likely to be modelled on those presently used in Abu
Dhabi.
The energy sector in the UAE is likely to continue seeing rapid changes and as
the economy, especially of Dubai, continues to recover, demand is likely to create more
opportunities for foreign private investment in the sector. For the time being, growth
will be managed through government solicited projects, with local participation and
economic interests. While this may dilute the benefits to a private sector investor, it
facilitates the ability to finance such ventures.
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Chapter 26
United Kingdom
Elisabeth Blunsdon 1
I
OVERVIEW
Great Britain’s gas and electricity markets were among the first to be liberalised and
unbundled in the European Union. Much of the experience gained from this process has
been influential in the development of unbundling in the rest of the EU. Now, however,
the markets face significant change as the need to achieve binding carbon reduction
targets during the worst economic downturn in a generation becomes pressing. The
government faces the unenviable task of guiding the sector through this period, but it
is fair to say that both market participants and potential investors are struggling to find
clarity in the current situation.
II
REGULATION
i The regulators
There is a single regulator for the electricity and gas sectors in mainland Great Britain. 2
GEMA, the Gas and Electricity Markets Authority, was established by the Utilities
Act 2000 (as amended) 3 and transferred the functions previously undertaken by the
Director General of Gas Supply, acting through the Office for Gas Regulation (Ofgas)
and the Director General for Electricity Supply, acting through the Office for Electricity
Regulation (Offer) into a single body. GEMA is entrusted with various statutory duties,
of which more later, but acts through the Office of Gas and Electricity Markets (‘Ofgem’).
1 Elisabeth Blunsdon is of counsel at Hogan Lovells.
2 Mainland Great Britain means England, Wales and Scotland. Northern Ireland’s energy
markets are regulated separately.
3 Section 1 of the Utilities Act 2000.
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Participants in the gas and electricity markets deal with Ofgem on a day-to-day basis and
Ofgem is referred to as the ‘Regulator’.
GEMA’s powers and duties largely derive from statute, principally the Gas Act
1986 and the Electricity Act 1989, which have been substantially amended over time. 4
Detailed provisions are set out in statutory instruments. Ofgem also publishes guidance
documents, 5 which provide practical information. This guidance is not legally binding.
There have been subtle shifts in the definition of the regulator’s powers and duties
over time. Emphasis has moved from an initial focus solely on competition, through
taking into account the interests of consumers to recognising the need for sustainability. 6
At present GEMA’s principle objective is to protect the interests of existing and future
consumers in relation to gas conveyed through pipes and electricity conveyed by
distribution or transmission systems. The interests of such consumers are their interests
taken as a whole, including their interests in the reduction of greenhouse gases and in
the security of the supply of gas and electricity to them. GEMA is generally required
to carry out its functions in the manner it considers is best calculated to further the
principal objective, wherever appropriate by promoting effective competition between
persons engaged in regulated activities. GEMA has powers under the Competition Act
to investigate anti-competitive activity, and has concurrent powers with the Office of Fair
Trading in respect of market investigation references to the Competition Commission.
In performing its duties, GEMA must also have regard to security of supply,
a licensee’s ability to finalise its licensed activities, the achievement of sustainable
development and to the interests of individuals who are disabled, chronically sick, of
pensionable age, with low incomes or residing in rural areas. 7 Subject to the former,
GEMA must carry out its functions in a manner which it considers is best calculated
to promote efficiency and economy on the part of licenced entities, protect the public
from dangers arising from the transportation and use of gas and electricity and secure
a diverse and viable long-term energy supply, with regard to the effect the carrying out
of its functions has on the environment. GEMA must also have regard to upholding
the best regulatory practice (in particular with regard to transparency, accountability,
proportionability and consistency) and to statutory guidance on social and environmental
matters issued by the government.
ii Regulated activities
Both the Electricity Act and the Gas Act are structured along the same lines, namely that
it is an offence under either act to carry out a licensable activity without authorisation.
Authorisation under both acts takes the form of either a licence or an exemption.
4 Consolidated and ‘as enacted’ versions of these Acts are available at www.legislation.gov.uk.
5 www.ofgem.gov.uk.
6 These changes can be seen in the successive changes to Sections 4AA of the Gas Act and 3A of
the Electricity Act.
7 There is a specific set of licence conditions relating to these special classes of individuals in the
licence of suppliers who supply domestic customers.
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Licences are issued by the Secretary of State pursuant to the relevant act and
are administered on a day to day basis by Ofgem. Exemptions are made by statutory
instrument and may take the form of a class exemption or a specific exemption which
is personal to a particular company. Licences are granted to persons (companies), not
assets. They do not, therefore, attach to an asset, or the land on which an asset is situated,
and they do not transfer on a sale of the asset or land.
Section 6 of the Electricity Act provides that the Secretary of State may issue a
licence in respect of the following licensable activities:
a the generation of electricity for the purpose of supplying premises;
b the transmission of electricity;
c the distribution of electricity;
d the supply of electricity to premises; and
e the operation of an electricity interconnector.
Supply, distribution and transmission licences may be limited in geographical area if the
licensee agrees. Supply licences may also differentiate between supply to domestic and
non-domestic (industrial and commercial, or I&C) premises.
The same legal person may not hold a transmission, distribution or interconnector
licence together with any other licence.
There are fewer licences for supply to domestic premises (even though, by numbers,
these customers form the largest single group of the supply market) because licences
for supply to domestic premises include conditions relating to provision of particular
services to customers, including those who are vulnerable or have special needs.
The Electricity (Class Exemptions from Requirement for a Licence) Order 2001
sets out class exemptions from the requirement to hold a licence. Any person that falls
within a specific class need not obtain a licence if it wishes to conduct a licensable activity.
Two of the more commonly used class exemptions are the exemption for generating
stations with a capacity of less than 50MW, and the exemption for on-site supply to
premises, which is available to embedded generators supplying direct to the site where
the generating station is situated. Specific exemptions may be granted by application to
the Secretary of State.
Section 7 of the Gas Act provides that the Secretary of State may issue a licence in
respect of the following licensable activities:
a transportation – the conveyance of gas through pipes to premises or to a pipeline
system operated by another gas transporter;
b shipping – the making of arrangements with a gas transporter for gas to be put
into, conveyed through or taken out of that gas transporter’s pipeline system;
c supply – the supply to premises of any gas conveyed to premises through those
pipes; and
d interconnector – the operation of a gas interconnector.
As with electricity licences, gas licences may be limited in geographical area and supply
licences are divided into those in respect of domestic and non-domestic customers.
Exemptions from the requirement for a licence in the gas sector are set out in the Gas
(Exemptions) Order 2011. The Secretary of State may also issue specific exemption by
statutory instrument.
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Production of natural gas is regulated under a separate regime which was
consolidated by the Petroleum Act 1989 and is administered by the Department for
Energy and Climate Change. The regime is outside the scope of this chapter but further
information can be found at og.decc.gov.uk.
Applications for licences are made in accordance with the relevant application
regulation. 8 Further information and guidance is provided on the Ofgem website. A
fee is payable with each application and the information that must be provided is set
out in the relevant application regulation. Once Ofgem has received the completed
application (at which point it is said to be ‘duly made’) the applicant must complete
and return the form of notice provided by Ofgem within 10 working days. The notice is
then published for at least 28 days, usually on Ofgem’s website. Assuming the applicant
meets the necessary criteria, Ofgem aims to process applications within 45 working days
of confirmation that the application is duly made. This period may be extended where
further information is required, or where an applicant is seeking exemption from certain
standard licence conditions. Ofgem carries out various checks as to the insolvency of an
applicant, whether any individuals associated with the applicant are disqualified directors
or have unspent convictions, and whether the applicant has previously had a licence
revoked or refused. Ofgem will also take into account any representations received
during the notice period described above. Ofgem may also request further information
from an applicant and failure to provide such information may result in a licence being
refused. In the event that a licence application is refused, the applicant has 21 days to
appeal the decision.
The grant of a licence under the Electricity Act or Gas Act authorises the
carrying out of the activity specified in the licence but it does not convey any other
rights. Construction of assets such as power stations, gas pipelines or electricity networks
requires the developer to obtain the relevant rights to land (by buying or leasing the
land) together with access rights, planning permission, (or for generating stations with
a capacity of greater than 50MW, a consent to construct a power station under Section
36 of the Electricity Act) 9 and all necessary environmental permits. Access routes for
electricity lines and gas pipelines can be obtained by compulsory purchase if landowners
consent is not forthcoming.
Licences in both sectors are subject to standard licence conditions, 10 which are
published on the Ofgem website. The standard licence conditions apply to all licensees
and may be changed from time to time. The change procedure is set out in the Utilities
Act 2000 and requires publication of proposed changes and a public consultation period
8 The Gas (Applications for Licenses and Extension and Restriction of Licences) Regulations 2010
(SI No 2155) and The Electricity (Applications for Licences and Extension and Restriction of
Licences) Regulations 2010 (SI No 2154).
9 A power station that burns gas also requires a consent to burn gas under Section 14 of the
Energy Act 1976.
10 Section 8 of the Gas Act 1986, Section 8A of the Electricity Act 1989.
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of at least 28 days. If a given proportion of licensees object, GEMA may not make the
modification. It may then refer the matter to the Competition Commission. 11
Licences may be granted subject to special conditions, or have certain standard
licence conditions disapplied or amended – there is, for example, a specific section
relating to domestic customers in both gas and electricity supply licences, which is
disapplied if the supplier is only supplying non-domestic customers and there are some
interconnector licences where the conditions requiring third-party access are relaxed.
Codes
The standard licence conditions require licensees to be party to various codes that set out
the operating rules and procedures for the relevant activity. The principal codes are the
Uniform Network Code (‘the UNC’) in the gas sector and the Balancing and Settlement
Code (‘the BSC’), Connection and Use of System Code (‘the CUSC’), Grid Code and
Master Registration Agreement (‘the MRA’) in the electricity sector.
Each transporter is required by its licence to publish a network code. The Joint
Office of Gas Transporters was established to administer a single code for all licensed
transporters. All licences issued under the Gas Act require a licence to become party to
the UNC. XoServe is the company that provides transportation transactional services,
including balancing services, to all signatories.
The BSC contains the rules for wholesale trading and settlement of electricity, and
is administered by Elexon. All licences must sign the BSC, as well as any non-physical
traders who are not licensed. The CUSC and Grid Code set out the technical rules
governing the electricity system. All licensed generators are required to sign both, as the
transmission operator. The MRA governs the registration of electricity meters and is
administered by Gemserv as agent for the MRA Service Company (MRASCo).
All the codes have the same legal architecture. Each takes the form of a framework
agreement by which the parties agree to be bound by the terms of the relevant code, and
the codes themselves. New parties are added by them signing an accession agreement.
The codes are subject to modification under a prescribed modification procedure which
requires industry consultation and Ofgem consent before a change can be made.
Licences are granted for an indefinite term. They may be revoked by the Secretary
of State on notice of not less than 25 years to be served not earlier than the date that is
10 years after the licence came into force or in accordance with the revocation provisions
that provide for revocation by the Secretary of State on 24 hours’ notice if the licensee
becomes insolvent, or on not less than 30 days’ notice where:
a the licensee agrees in writing that the licence should be revoked;
b
c
d
the licensee has failed to pay the licence fee;
the licensee has failed to comply within an enforcement order issued by GEMA,
the Competition Commission or the Secretary of State under relevant legislation,
or pay any financial penalty within the specified time frame; or
the licensee has not commenced the licensable activity within a specified time or
has ceased to carry out the licensed activity within the specified area.
11 Sections 23, 24 of the Gas Act 1986, and Sections 11, 12 of the Electricity Act 1989.
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iii
United Kingdom
Transfers of control and assignments
Transfers of regulated assets are most commonly effected by the sale of the company
that owns the assets rather than a sale of the asset, because while all licences contain a
provision permitting assignment, such assignment requires the prior written consent of
the Secretary of State and in practice obtaining such consent involves an almost identical
procedure to that required when applying for a new licence. Licences in the gas and
electricity sectors do not contain provisions regarding change of control per se, however,
electricity distribution licences, electricity transmission licences and gas transportation
licences do contain provisions that create a regulatory ringfence around the regulated
asset. In the event of deterioration in a company’s creditworthiness, or on a sale to an
entity that does not meet the required creditworthiness threshold, Ofgem may tighten
the ringfences and ultimately place the business into energy administration. 12
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration and unbundling
The British market was one of the first in Europe to be unbundled. At privatisation
the electricity industry was split into generators, transmission companies and public
electricity suppliers that performed the functions of distribution and supply. The public
electricity suppliers were unbundled and distribution because a licensable activity in its
own right under the Utilities Act 2000. In 2001, with the introduction of NETA (New
Electricity Trading Arrangements), the structure of the electricity market changed from
the old Pool model to a bilateral trading model. Further structural change occurred
in 2005 when the operation of the three transmission networks 13 on mainland Great
Britain was taken over by National Grid group.
It is prohibited by statute for licensed operators of transportation, transmission,
distribution and interconnector assets to hold any other licence under either of the Acts.
This ensures that these businesses remain fully independent and unbundled within
the relevant sector. That said, it should be noted that the energy supply markets are
dominated by vertically integrated groups of energy companies. There is some concern
about this vertical integration and Ofgem has recently launched several investigations.
ii Transmission/transportation and distribution access
As a general matter of policy, it is considered preferable to have monopoly providers of
network services within a given area rather than a proliferation of networks competing
12 Energy Administration is a specific administration scheme for companies operating energy
networks. It is designed to ensure continuity of supply in the event of a network operator
suffering financial difficulties.
13 The three networks were those in England and Wales, owned and operated by National Grid,
and the two in Scotland owned and operated by Scottish and Southern and Scottish Power
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against each other. The quid pro quo for the grant of monopoly rights is that the network
operator must provide regulated third-party access and that it is subject to price control.
In terms of specific geographical areas, National Grid Electricity Transmission
plc (‘NGET’) holds a transmission licence in respect of the electricity national grid
that covers the whole of Great Britain. There are other transmission licences, but all
have licences limited to a particular area. National Grid Gas plc (‘NGG’) holds a gas
transportation licence which similarly covers the whole of the National Transmission
System (NTS) in mainland Great Britain. There is no licensable activity analogous to
distribution in the gas sector, even though there is a high-pressure system (the NTS) and
a lower-pressure system (local distribution zones or LDZs). All transportation of gas,
whether it be through the NTS or LDZs, requires a transporters licence. The grant of a
licence does not confer exclusive rights, although the rights of licensees may be restricted
to a certain area. In any event duplication of network assets in an area where there is
access to existing infrastructure would face challenges from local planning authorities.
Consumers have been free to choose their energy supplier for over 10 years. Ofgem
monitors the retail, and in particular the domestic, market very closely and is concerned
that there is still insufficient switching of suppliers by customers. It has been very active in
this area and is currently undertaking a retail market review, the most recent stage of which
is a consultation on improving the reporting transparency of large energy suppliers so that
consumers can compare tariffs more easily. There is also concern about the dominance of
the big six energy suppliers, who according to Ofgem share 99 per cent of the domestic
supply market between them. 14 In a recent report 15 published by the Institute for Public
Policy Research, this dominance is identified as having a negative effect on competition in
the retail energy market leading to increased prices for consumers.
iii Rates
As previously mentioned, network assets are subject to price control, which is implemented
by licence conditions specific to each licensee.
Historically, price control used the RIP-x model, but following a review this was
changed to the RIIO model – revenue set to deliver strong incentives, innovation and
outputs.
Revenue that can be earned by a regulated entity is limited in order to ensure timely
and efficient delivery, the ongoing financeability of network companies, transparency
and predictability and a balance between costs paid by current and future consumers.
Entities will be incentivised to deliver outputs efficiently over time, with a focus on
the longer term – including eight-year prior control periods, rewards and penalties for
output delivery performance, a symmetric upfront efficiency incentive rate for all costs
and uncertainty mechanisms where they add value for customers.
Innovation will be encouraged through the use of core incentives in the price
control package, the ability to pass responsibility for delivery to third parties and stimulus
for innovation, building on the Low Carbon Networks Fund. Outputs will be set out
14 Ofgem – ‘The Retail Market Review’ – Findings and Initial Proposals 2011.
15 IPPR – ‘The True Cost of Energy’ April 2012.
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in the licence, so consumers will know what they are paying for. Outputs will reflect
enhanced engagement with stakeholders. The first round of price control reviews under
RIIO is currently underway for electricity and gas transmission, gas distribution and
electricity distribution. These will be implemented over the next two to three years as the
existing price controls come to an end.
iv Security and technology restrictions
Unlike in the United States, where the US Grid reliability and Infrastructure Defense
Bill has been enacted to bolster the national grid against threats including terrorist and
cyber attacks, there is no specific legislation addressing cyber-security concerns in respect
of infrastructure; however, that is not to say that there are no measures in place. If a
cyber-security threat were to affect an energy utility company’s operational capability,
and this led to security-of-supply concerns, the government has existing powers to take
control of fuel and electricity supplies under Sections 1 and 2 Energy Act 1976. In
addition, in 2010, the UK government put in place a £650 million National Cyber
Security Programme to combat cyber threats, with 20 per cent of that being directed
towards the cyber-protection of critical infrastructure.
The Centre for the Protection of National Infrastructure (‘CPNI’) is the main
government authority in this area, working to identify and mitigate vulnerabilities
in the national infrastructure that could be exploited by cyber-security threats. As
much of the UK’s infrastructure is not in government hands, part of CPNI’s role is to
provide protective security advice to businesses and organisations across the national
infrastructure, including critical national infrastructure organisations such as the national
grid, public utilities and financial centres.
IV
ENERGY MARKETS
i Development of energy markets
The wholesale gas and electricity markets in Great Britain are well established. The
markets for both commodities operate on the basis of bilateral contracts between market
participants. Parties are free to choose the terms on which they trade and the price at
which they trade. There is no compulsory price disclosure, although there are various
entities that produce price indices from aggregated market data.
Gas trading
Gas can be traded at entry points, within the NTS and at exit points. It is also possible
to trade capacity rights for entry on to the NTS and gas in storage. Gas being traded at
entry points is generally referred to as being traded at the beach – a reference to the fact
that Great Britain’s physical gas supplies are sourced from the North Sea and the beach
is the point where the offshore pipeline makes landfall, just before the entry point to the
NTS. Gas traded at entry points may be traded under the Beach 2000 terms, which are
a standard set of terms and conditions, or on bespoke gas sales agreements. There are no
specific regulatory requirements as to the terms on which trades take place. Trading at the
beach involves a physical transfer of title to the gas, hence the Beach 2000 terms contain
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provisions relating to title, quality and pressure as well as provisions for determining the
damages payable where either party fails to perform.
Only licensed shippers may put gas into the NTS, and only licensed shippers
may trade gas within the NTS. Physical title to all gas within the system vests with the
relevant transporter. Shippers have a right to volumes of gas on an energy equivalence
basis, not a right to specific molecules of gas. Trades within the NTS are deemed to occur
at a notional point called the national balancing point (NBP). 16 Trades are made between
shippers by way of trade nominations under the UNC. One party makes an acquiring
trade nomination and the other makes a disposing trade nomination for an equal volume
of gas. The nominations must match otherwise both will be rejected by NGG.
When a trade is made the total amount of gas in the system remains the same,
but the volume allocated to each party’s balance is altered. Shippers must balance their
positions each day. 17 Nominations may be made and adjusted prior to the beginning of
a day and may be renominated throughout the day (subject to rules on deemed flow
rates). Trade nominations may also be made throughout the day. Following the end of
each day, the system operator collates the physical flows and trade nominations of each
shipper and compares inputs and outputs to determine whether each shipper is balanced.
If a shipper is out of balance, it is deemed to buy sufficient gas from the system if it is
short or sell sufficient gas to the system if it is long to cancel the imbalance. The price at
which the deemed purchase is made can be very high and the price at which the deemed
sale is made can be very low, to incentivise shippers to balance. The vast majority of
NBP trades are made subject to the NBP ’97 terms, or under an ISDA master agreement
with an NBP annex that sets out the requirements for nominations, etc. The NBP ’97
terms have very limited credit support provisions, so it is common to see them amended,
particularly with regard to credit.
Trades just outside the exit points to the NTS are usually between shippers and
licensed suppliers, although many suppliers are also shippers, enabling a single entity to
offtake gas from the NTS and supply it to premises.
NGG is responsible for maintaining physical and operational balance on the
NTS, so will assess nominations prior to the day and during the day against actual supply
and demand. NGG have various tools available to ensure system balance, including the
use of linepack 18 and interruptible contracts with offtakers. 19
NGG also has access to the balancing market, which is an independently operated,
cleared market where shippers can make bids or offers in respect of volumes of gas. Bids
or offers may be within system (title) trades or physical or locational trades that involve
entry or exit of gas. NGG may accept bids or offers in the balancing market to achieve
physical balance. It is incentivised under its transmission licence to take such actions as
16 The NBP is also the point at which NGG calculates transportation charges.
17 ‘Day’ is defined in the UNC and each day runs from 6 a.m. to 6 a.m.
18 NGG’s use of linepack is subject to regulatory constraints.
19 Offtakers have the option of entering into interruptible contracts under which supply may be
interrupted to a specified number of times each year, in return for paying reduced [capacity]
fees.
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efficiently as possible. The prices that it pays in respect of balancing actions determine
the cash-out charges for shippers that are out of balance.
Electricity trading
Electricity is traded across the national grid between generators, suppliers and trading
entities.
Any entity that has a licence granted under the Electricity Act is required to
become a party to the BSC, however, it is also possible for parties who do not hold a
licence to be party to the BSC. These are non-physical traders (i.e., only trading within
system) such as banks and trading houses. All parties to the BSC each have two energy
accounts: a to-energy account and a from-energy account. The market operator (Elexon
Limited (‘Elexon’)) credits and debits these accounts with traded volumes in each halfhourly
settlement period and with physical flows onto and off the system where parties
are licensed. Energy trades take the form of notifications which are made to Elexon
in respect of each settlement period. Elexon then aggregates all the volumes traded or
flowed or by each party in each settlement period and determines whether or not each
party was in balance or not. If the party is not in balance, it is deemed to buy from the
system if it is short or sell to the system if it is long to cancel the imbalance. The price
at which the deemed purchase is made can be very high and the price of the deemed
sale can be very low, or even negative, which incentivises parties to balance. Most trades
are effected either under the industry standard grid trade master agreement (‘GTMA’)
or under an ISDA master agreement with a GTMA annex. Bespoke power purchase
agreements (PPAs) are also used, particularly for longer-term structured arrangements.
In parallel with the electricity trading activities, NGET is responsible for ensuring
physical balance of the system in real time. Physical participants must submit a final
physical notification (‘FPN’) 20 no later than one hour before the start of each settlement
period (known as gate closure). Trades must also be notified, via notifications, within the
same time frame. Parties may not adjust their position once gate closure has occurred
although they are free to do so up to this point. At gate closure NGET assesses the
overall balance of supply and demand against FPNs and notifications. If it needs to
take balancing actions it will assess the bids and offers made in the balancing market by
physical players and accept the most appropriate. It continues to monitor the market and
take appropriate action to maintain physical balance throughout the settlement period.
After each settlement period each party’s actual position is determined and if there is an
imbalance, cash out occurs as described above.
The balancing market is completely separate from the general trading market.
The balancing market is there to provide a physical balancing tool to NGET. Physical
players are required under the BSC to submit bid offers into the balancing market and
are required to either dispatch 21 or curtail demand if instructed to do so. The operation
of the balancing market is regulated to ensure that any balancing actions are as efficient
20 FPNs are submitted under the Grid Code rather than BSC.
21 There is no concept of ‘central dispatch’. Each party is responsible for self-dispatch.
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as possible. Prices in the balancing market are used to derive the imbalance price at which
out-of-balance parties are cashed out.
Credit support
For completeness, mention should be made of credit support as it is credit considerations
that typically dominate discussions between trading counterparties. Credit support of
some sort in respect of the mark-to-market value of each counterparty’s relative position
is often required, the nature of which will depend on the creditworthiness of each entity.
Counterparties with a poor credit rating may find themselves having to post daily
cash collateral under margining arrangements. More modern forms of standard form
contracts such as ISDA and the GTMA contain material adverse change (MAC) clauses
that allow one party to call for additional credit support if there is a deterioration in the
creditworthiness of the other party. In the older forms of contract such as the NBP ’97
it is very unusual not to see an amendment incorporating similar language. It is also
common to see cross-commodity master netting agreements in place in respect of gas,
electricity and carbon positions.
ii Energy market rules and regulation
As previously described, participants in the energy markets may require a licence, and
will need to be party to the relevant industry codes. Depending on the nature of a
particular entity and its particular activities it may also fall within the jurisdiction of
financial regulation. Traditionally, own-account energy trading was largely without the
realms of financial regulation, but particularly in the EU, we have seen an increasing
trend towards financial regulation of energy trading. A detailed analysis of this issue is
outside the scope of this review.
Another area of increasing influence from Brussels is in the area of market
manipulation. Until recently general antitrust law was used where market manipulation
was suspected. However in 2011 the EU enacted the Regulation on Energy Market
Integrity and Transparency (‘REMIT’), 22 which is aimed specifically at the wholesale
energy markets. Again, the details of REMIT and its application are outside the scope
of this review, save to say that REMIT substantially increases the regulator’s powers in
this area.
iii Market developments
The electricity supply market is dominated by the so called big six suppliers, 23 all of
whom are vertically integrated groups of companies with at least 2 million customers. As
previously mentioned, there is concern that this may be harmful to competition.
There has also been an exit from the market by several high-profile traders,
particularly US firms, in the past decade and in recent years the number of non-physical
22 Council Regulation (EU) No. 1227/2011 on Wholesale Energy Market Integrity and
Transparency.
23 Scottish Power, Scottish and Southern, EDF, E.ON, RWE (nPower) and Centrica (British
Gas).
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traders, particularly banks, has fallen considerably. Ofgem has had concerns about
market liquidity for several years and in 2008 it launched its energy supply probe to
investigate the subject. In February 2012 it set out proposals whereby the big six will be
required to sell a range of specific key trading products designed to improve liquidity at
auction, on a regular basis. The current proposal is that 25 per cent of each party’s annual
generation is to be sold this way. The consultation closed on 8 May 2012. Ofgem is due
to put forward a final decision later in the year.
The government is currently undertaking a major project in the electricity market
under its electricity market reform (‘EMR’) process. Broadly, EMR will introduce a
capacity market, a feed-in-tariff with contract for difference (‘FiT CfD’) for renewable
and nuclear generation, a carbon price floor, which will take the form of an input tax
on fuel for electricity generation, and an energy performance standard, which will limit
the carbon output of new plant, effectively preventing the building of any further coal
plant that is not fitted with carbon capture and storage capability. These measures will
sit alongside existing market arrangements. The possible impact of EMR is discussed in
greater detail in Section VII, infra.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
Renewable technologies have benefited from government support since the early 1990s
when the Non-Fossil Fuel Obligation (‘the NFFO’) came into effect. The NFFO was
replaced by the current Renewables Obligation (‘the RO’) in 2002. The RO places an
obligation on suppliers to source a minimum percentage of the volume that they supply
each year from renewable sources. 24 At the end of each year suppliers must submit
sufficient renewable obligation certificates (‘ROCs’) to Ofgem, or they can pay the
‘buyout’ price 25 as set out in the relevant Renewables Obligation Order (‘ROO’) 26 to
the extent that they have a shortfall of ROCs. A ROC represents a volume of electricity
generated by an accredited renewable generator. Initially, one ROC was issued for 1MWh
of electricity; however, in order to incentivise the development of new, but riskier and
more expensive technologies, banding was introduced in 2009. A further banding review
was instigated in 2011, which proposed more granular banding. The final outcome of
that review is due shortly and the final proposals will apply from April 2013. ROCs are
issued to accredited generators by Ofgem and generators then sell them on either to
traders or suppliers. Buyout payments paid to Ofgem go into a buyout fund, which is
distributed among suppliers in proportion to the number of ROCs they have presented
against the total number of ROCs in that compliance period. ROC support is available
for 20 years for eligible projects. As a result of the EMR process, ROC accreditation will
not be available after 1 April 2017. From that date renewables support will be delivered
24 Currently 15.8 per cent (compliance period 2012–2013).
25 Currently £40.71 per ROC (compliance period 2012–2013).
26 The Renewables Obligation is implemented in a slightly different form in each of England and
Wales, Scotland and Northern Ireland, so there are separate orders for each jurisdiction.
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via the FiT CfD mechanism. Projects accredited prior to 1 April 2017 will continue to
receive support under the ROC scheme for 20 years, with consequential amendments
to the existing scheme to take account of the removal of the Renewables Obligation. 27
The FiT CfD mechanism is due to be introduced on 1 April 2014 and during the period
1 April 2014 to 31 March 2017 project developers may choose whether they wish to
receive ROCs or enter into a FiT CfD arrangement.
Feed-in tariffs (‘FiTs’) were introduced in 2010 as a means of supporting smallscale
(sub-5MW) generation. Owners of eligible small-scale generation plant receive a
payment from their electricity supplier for each unit of electricity that they generate
for own use, as well as a guaranteed payment for any surplus electricity that is sold
back to the grid. The level of payment depends on the technology used for generation.
Large electricity suppliers are obliged to enter into FiT arrangements with FiT eligible
generators. Smaller suppliers may elect to do so if they wish.
Following the introduction of the FiT scheme, there was a higher than expected
take up of FiTs for solar photovoltaic (‘PV’) generation. The government subsequently
took the decision to reduce the solar PV FiT but the implementation was successfully
challenged by legal action as the reduction was to be applied retrospectively. Ultimately,
the reduction in FiT was put in place by statutory instrument but the legal wrangles have
caused confusion and uncertainty in a business which was already nervous due to EMR.
The Renewable Heat Incentive (‘RHI’) is designed to support the generation of
heat from renewable sources at all scales. Implementation of RHI has also been subject to
legal delays due to issues with state aid clearance, although these have now been resolved.
The non-domestic scheme went live in November 2011 and is currently the subject of
further consultation. The take up of RHI has been low so far with few accreditations.
The Climate Change Levy (‘the CCL’) was introduced in the Finance Act 2000
as an end-user tax on energy consumption. Renewable and combined heat and power
(‘CHP’) electricity is CCL‐exempt and accredited generators of CCL exempt electricity
receive levy exemption certificates (‘LECs’) issued by Ofgem, which they can sell. Unlike
ROCs, LECs are not tradeable separately from the electricity to which they relate. The
two must therefore be sold together in order that the ultimate end user of the electricity
can redeem the LECs and claim exemption from the CCL. Given the nature of electricity,
proving the physical path of such electricity is impossible. Her Majesty’s Revenue and
Customs (‘HMRC’) therefore looks for an unbroken contractual chain to establish the
link from generator to end user.
The government has recently announced that CHP plants will not receive LECs
after 1 April 2013. Such plants will, however, receive favourable treatment of their fuel
inputs under the carbon price floor arrangements.
ii Energy efficiency and conservation
The CRC Energy Efficiency Scheme is a mandatory cap and trade scheme that applies
to large non-energy-intensive organisations in the public and private sector and which is
27 See the Department of Energy and Climate Change’s ‘Planning our electric future: technical
update’, December 2011, for further information.
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designed to improve energy efficiency. The Scheme came into force on 1 April 2010 and
will be developed over several phases.
Participants will buy emission allowances based on what they predict their
CO 2
emissions will be during the relevant year, and will be allowed to buy or sell the
allowances from each other in the secondary market. At the end of each compliance year,
participants will be obliged to surrender sufficient allowances to cover the amount of CO 2
they have emitted. In order to incentivise participants to improve their energy efficiency,
participants will be ranked annually in a league table according to the action they have
taken to improve their energy efficiency. The government will then recycle the revenue
raised from the sale of allowances back to participants, applying either a bonus or penalty
– the size of which will be based on the participant’s position in the league table.
The scheme has been criticised for being too complicated, so the implementation
of phase 2 has been postponed and a consultation issued on possible simplifications.
The government has also established the Green Deal, which will be launched in
October 2012. Private firms will make loans to occupiers (domestic and non-domestic)
and private landlords, for the purpose of making energy-efficiency improvements to
properties.
The key principle is that energy efficiency improvements should pay for themselves.
The Energy Company Obligation (‘ECO’) will be integrated with the Green Deal, and
will require energy companies to assist in cases were the this is not the case, but there are
strong policy reasons for promoting energy efficiency measures (for example, supporting
the upfront costs of basic heating and insulation for those on low incomes).
Liability to repay Green Deal finance will attach to a property’s energy bill. Thus,
when a person ceases to be the billpayer, liability for any debt under the plan will pass to
the next billpayer.
iii Technological developments
The rollout of smart meters has been identified by the government as an important
part of the transition to a low-carbon economy. Energy suppliers will be responsible for
replacing gas and electricity meters with smart meters during the rollout programme due
to start in 2014 and complete in 2019. DECC is managing the implementation of the
programme.
Another key technology identified by the government is CCS. In early April 2012
the government relaunched its competition for CCS, at the same time as it released its
CCS roadmap. The competition will provide £1 billion in support to reduce the costs
of CCS so that it can be deployed during the 2020s. The chosen programme will be
used to address barriers to cost competitiveness, stimulate new investment in CCS and
encourage knowledge sharing. Bids must be submitted by early July 2012.
VI
THE YEAR IN REVIEW
The sector continues to feel the effects of the credit crunch, with credit availability
remaining very tight. Over the past year there has been some M&A activity including
the announcement by GDF Suez that it intends to acquire the remaining 30.23 per
cent stake in International Power plc. The most high-profile sale announced was that of
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E.ON and RWE’s interest in the Horizon Nuclear Power JV – which means that E.ON
and RWE are now out of the running to build the UK’s next generation of nuclear power
plants. Several large coal-fired power stations have announced plans to convert to run on
biomass, including Drax, which plans to develop a 426 MW biomass co-firing facility at
the Drax site. Activity in the offshore wind sector has continued with the Barrow, Robin
Rigg and Gunfleet Sands offshore transmission projects all reaching financial close and
the next phase of projects underway.
VII
CONCLUSIONS and OUTLOOK
The market currently faces a good deal of uncertainty. The government is trying to
reconcile three sometimes contradictory objectives, namely decarbonisation, ensuring
energy security and ensuring affordability for consumers. Policy proposals have been
many and far reaching over the past 18 months, but at the current time there is little
detail as to how those policies – and particularly EMR – will be implemented. This
causes uncertainty, which affects investor confidence, already poor as a result of the
financial crisis. A great deal of political capital has been invested in offshore wind and
nuclear generation. Some commentators are beginning to question the economics of
offshore wind, and plans for new nuclear were dealt a blow with the withdrawal of RWE
and E.ON from the nuclear build programme. Significant infrastructure investment is
also required, both to replace existing assets and to develop the system in preparation for
the expected increase in intermittent and geographically remote generation.
What has been notable by its absence during the EMR process has been
consideration of the contribution of natural gas in the future. Given the amount of gasfired
generation already installed, the government’s call for evidence on the future of gas
is to be welcomed, particularly if it opens a debate on how the EMR proposals will affect
the gas market as gas moves from its current role as baseload to providing back up for
intermittent generation in future.
A draft Energy Bill is due in late May, which, hopefully, will clarify many of the
outstanding questions. The sector needs clarity, but it also needs clear investment signals.
The upcoming legislation must be clear and coherent if investors are to be tempted back
into the market.
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Chapter 27
United States
Michael J Gergen, Natasha Gianvecchio and David L Schwartz 1
I
OVERVIEW
Energy regulation in the United States is complex, broad and enforced by a variety of
federal and state governmental entities. Further, it is continually evolving in response
to global and national events, market shifts, political dynamics and priorities, and
technological advances. As such, this chapter is intended to be an overview of the nature
and scope of energy regulation and markets, with a particular emphasis on the federal
regulation of electric energy and various regional bulk power markets.
II
REGULATION
i The regulators
Multiple federal and state agencies, departments and other governmental entities
regulate US energy development, and the ownership, control and operation of electric
generation, transmission/transportation and distribution, including with respect to the
rates, terms and conditions of wholesale and retail services, as well as energy market rules.
The Federal Energy Regulatory Commission (‘FERC’) is an independent federal
regulatory agency established by the United States Congress to regulate wholesale sales
of electric energy and the transmission of electric energy in interstate commerce. FERC
is also responsible for hydroelectric project licensing and safety, natural gas pipeline
transportation rates and services and oil pipeline transportation rates and services.
FERC’s authority is granted, and limited, by statutes, including the Federal Power Act, as
amended, the Natural Gas Act, as amended, the Interstate Commerce Act, as amended
and the Public Utility Holding Company Act of 2005.
1 Michael J Gergen, Natasha Gianvecchio and David L Schwartz are partners at Latham &
Watkins LLP.
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The Nuclear Regulatory Commission (‘the NRC’) is an independent federal
regulatory agency established by Congress to formulate policies and regulations governing
nuclear reactor and materials licensing and safety. The NRC’s authority is also granted,
and limited, by statutes, including the Atomic Energy Act of 1954, as amended, and the
Energy Reorganization Act of 1974, as amended.
The Department of Energy (‘the DOE’) is an executive department created in
1977 whose current mission ‘is to ensure America’s security and prosperity by addressing
its energy, environmental and nuclear challenges through transformative science and
technology solutions’. The DOE is led by the Secretary of Energy, a member of the
President’s cabinet.
Numerous other federal agencies and departments regulate certain aspects of the
US energy industry, including the Environmental Protection Agency, the Commodities
Futures Trading Commission, the Federal Trade Commission, and the United States
Departments of Agriculture, the Interior and Justice.
The distribution and retail sale of electric energy and natural gas are generally
governed by individual state regulatory agencies (often called public utility commissions,
public service commissions or ‘PUCs’) or municipal agencies. PUC jurisdiction is created
by state constitutions and statutes and, like most state regulation in the United States,
is also subject to the supremacy of the United States Constitution and federal statutes,
except in certain limited circumstances.
ii Regulated activities
Many aspects of energy development, generation, transmission/transportation, and
distribution in the United States are subject to some type of federal or state regulation.
FERC regulates the rates, terms and conditions of wholesale sales of electric energy
in interstate commerce and transmission service in interstate commerce. FERC also
regulates the rates, terms and conditions of natural gas and oil pipeline transportation
services. Entities making sales of jurisdictional products or services obtain rate approval
from FERC. FERC rates are typically either cost-based (i.e., based on the costs of
providing the product or service including a reasonable return on its equity investment)
or market-based (i.e., negotiated or market-determined). FERC also has extensive
regulatory authority over entities subject to its jurisdiction, including with respect to
issuances of securities, direct or indirect transfers of assets, accounting, recordkeeping
and reporting.
State PUCs generally regulate the rates, terms and conditions of retail sales and
distribution of electric energy and natural gas.
Siting approvals for the development and construction of new energy assets are
often required at the state or local government level, particularly with respect to electric
generation and transmission facilities. FERC has siting approval authority with respect
to hydroelectric generating facilities to be constructed on navigable waterways and
interstate natural gas pipelines and storage facilities. In 2005, Congress also gave FERC
‘backstop’ siting authority to issue permits for the construction of transmission lines
when the DOE identifies important transmission ‘corridors’ for the relief of transmission
constraints, although the scope of that authority remains unclear.
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iii
United States
Ownership, market access restrictions and transfers of control
Other than with respect to nuclear energy and other strategic assets, there is little restriction
on foreign ownership of energy assets in the United States. FERC approval is generally
required for the direct or indirect transfer of electric energy assets subject to FERC’s
jurisdiction. In reviewing a proposed transaction, FERC must determine whether the
transaction is consistent with the public interest, including the effect on competition, the
effect on rates and the effect on regulation. FERC also considers whether the transaction
would result in the cross-subsidisation of a non-utility affiliate of a public utility or the
pledge or encumbrance of utility assets for the benefit of a non‐utility affiliate of a public
utility.
Certain states also require that entities obtain PUC approval prior to the
direct and, in some jurisdictions, indirect transfer of assets subject to the jurisdiction
of the PUC. While many state statutes require PUCs to evaluate whether a proposed
transaction is consistent with the public interest, PUCs vary as to whether they interpret
their jurisdiction as requiring a showing that the transaction will not result in net harm
to the public or a showing that the transaction will provide net benefits to the public.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
SERVICES
i Vertical integration, unbundling and open access
The bulk power transmission grid in the continental United States comprised three
largely separate grids in the eastern and western United States and Texas. Within these
three grids are hundreds of control areas made up from transmission facilities operated
or owned by investor-owned, publicly owned and government-owned utilities. Since the
early 1990s, both the federal government and many states have worked to liberalise the
wholesale and retail electricity markets, including state efforts to have state-regulated
public utilities divest some or all of their electric generation and federal efforts to make
bulk power transmission facilities available to others on an open access basis.
In 1992, Congress amended the FPA to authorise FERC to order interstate
transmission-owning public utilities to provide any electric utility, federal power
marketing agency, or any other person generating electric energy for wholesale sales
open and non-discriminatory access to their transmission facilities. As envisioned by
Congress, such open access would allow bulk power consumers and suppliers to enjoy
the benefits of competition in bulk power markets, as well as in those downstream retail
power markets liberalised by states.
In 1996, FERC issued Order Nos. 888 and 889 to establish the foundation
for the development of competitive bulk power markets by directing that bulk power
transmission services be provided on an open access basis that is just, reasonable and
not unduly discriminatory or preferential. Order No. 888 required that all FERC
jurisdictional transmitting utilities in the United States file a pro forma open access
transmission tariff (‘OATT’) and functionally unbundle their wholesale power services
from their wholesale and retail transmission services. Order No. 888 also encouraged
transmitting utilities to convey operational control of their transmission facilities to
independent system operators (‘ISOs’) or other independent regional transmission
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entities, which led to the formation of ISOs in regions including the large majority of
electrical load in the United States.
The pro forma OATT requires transmitting utilities to provide open, not unduly
discriminatory, access to their transmission system to transmission customers and
addresses the terms of transmission service, including the terms for scheduling service,
curtailments and the provision of ancillary services. Transmitting utilities are permitted
to vary from the required pro forma terms of service if FERC finds that their proposed
variations are equally or more conducive to the OATT’s open access objectives. Order
No. 889 required codes of conduct governing how participants in the wholesale power
markets should interact with transmission service providers and the establishment of
electronic bulletin boards (open access same-time information systems) for the posting
of details regarding available transmission capacity.
Since Order Nos. 888 and 889, FERC has issued a range of major orders updating
and expanding its open access policies to address such matters as: the formation of and
participation in RTOs; pro forma procedures and agreements for interconnection of
generation to the bulk power grid; changes to the pro forma generator interconnection
procedures and agreements to facilitate interconnection of wind generators; general
rules to facilitate more open and transparent planning and use of wholesale transmission
facilities; and most recently, general rules regarding transmission planning and cost
allocation. FERC is currently considering whether reforms to its open access policies
are necessary to eliminate possible barriers to the integration of wind, solar and other
variable energy generation resources.
ii Rates
Economic regulation of most of the bulk power transmission system is administered
by FERC, including regulation of the rates, terms and conditions for the transmission
of electric energy in interstate commerce. Most FERC-regulated transmission services
are provided at embedded cost-of-service rates that provide a return of investment as
well as a FERC-determined reasonable rate of return on common equity. FERC also
has permitted so-called ‘merchant’ transmission projects (i.e., transmission that is not
included in a cost-of-service rate base) to charge negotiated rates for transmission service.
In 2005, Congress amended the FPA to direct FERC to develop rate incentives
to encourage certain transmission development. 2 In 2006, FERC issued regulations
to provide on a case-by-case basis a variety of cost-of-service rate incentives for new
transmission projects that improve reliability or reduce cost. These incentives include
incentive rates of return on equity for new investment, use of a hypothetical capital
structure during construction, full recovery of prudently incurred construction work
in progress in rate base during construction, full recovery of prudently incurred costs
of abandoned projects, and accelerated depreciation. To obtain one or more of these
incentives an applicant must show that there is a nexus between the incentive being
2 This legislative directive was prompted by the August 2003 electric grid blackout which
adversely affected large portions of the eastern United States and Ontario, Canada and a
concern that there had been a long relative decline in the level of transmission investment.
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sought and the investment being made. FERC currently is considering potential changes
to the scope and implementation of its transmission incentives regulations and policies.
Since 2000, FERC has permitted certain merchant transmission projects to
charge negotiated rates for transmission service under OATT-based transmission service
agreements. Initially, FERC required merchant transmission facilities to hold open
seasons for the full capacity of a planned project. Since 2009, FERC has permitted certain
merchant transmission project developers to allow ‘anchor customers’ to pre-subscribe
some percentage (to date, typically not more than 50 per cent) of the capacity of a
proposed project through long-term transmission service agreements that can provide
for up-front payments by the anchor customer to facilitate project construction. The
remaining project capacity not committed to anchor customers will be made available
to later customers selected through an open season process detailed in the project’s
OATT and these customers will be entitled to obtain service under terms and conditions
generally comparable to those available to anchor customers. FERC is currently
considering potential reforms to its policies concerning the allocation of capacity on new
merchant transmission projects and new cost-based, participant-funded transmission
projects (that historically have not been subject to open season or other OATT-based
open access requirements).
iii Security and technology restrictions
Prior to 2005, the United States relied on voluntary compliance by participants in the
bulk power industry with reliability requirements for operating and planning the bulk
power system coordinated through the North American Electric Reliability Corporation
(‘NERC’) and various related regional entities. In 2005, Congress responded to the
previously mentioned August 2003 blackout by amending the FPA to provide for a
system of mandatory, enforceable reliability standards to be developed by a FERCcertified
‘electric reliability organisation’ or ‘ERO’, subject to review and approval by
FERC. For purposes of approving and enforcing compliance with reliability standards,
FERC has jurisdiction over the FERC-certified ERO, any regional reliability entities,
and all users, owners and operators of the bulk power system, including public and
governmental entities not otherwise subject to FERC jurisdiction under the FPA. FERC
certified NERC as the ERO and in various subsequent orders has defined the bulk power
system and approved a number of reliability standards proposed by NERC.
IV
ENERGY MARKETS
i Development of energy markets
Throughout certain regions in the United States, ISOs and regional transmission
organisations (‘RTOs’) operate transmission facilities and administer energy markets.
FERC has prohibited any one set of market participants (including transmission
owners) from controlling decision making within an ISO or RTO. FERC’s Order No.
2000 imposed significant regulatory requirements upon ISOs and RTOs regarding the
independence of an energy market administrator, the performance of the energy markets
and the elimination of discrimination. FERC left considerable discretion to market
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participants to determine an ISO’s or RTO’s governance structure, geographical scope
and type of market services.
The following ISOs and RTOs are currently operating: PJM Interconnection LLC,
New York Independent System Operator, ISO New England Inc, Midwest Independent
Transmission System Operator Inc, Electric Reliability Council of Texas (‘ERCOT’),
Southwest Power Pool and California Independent System Operator Corp. Of these
RTOs, only ERCOT is not subject to FERC’s regulatory oversight, as ERCOT is deemed
to be electrically isolated from the rest of the transmission grid.
Each ISO and RTO offers different energy products in its markets. While all
of the existing ISOs and RTOs administer some form of bid-based markets for one or
more energy products (i.e., where the highest price bid in any hour sets the market price
for the product within that applicable region, node or zone), some provide real-time
and day-ahead markets, while others do not. In addition, some of the ISOs and RTOs
offer markets for the sale of capacity (i.e., the ability to produce energy) separate from
other energy products. Such forward capacity markets are structured differently in each
market and the details associated with the ancillary service markets differ as well. Each
market has an independent market monitor, as FERC required by Order No. 719, but
the nature and scope of the market monitors’ roles differ.
ii Energy market rules and regulation
Each RTO and ISO develops its own market rules through the market participants’
stakeholder approval process. Market rules for all RTOs and ISOs must be filed with
and approved by FERC prior to implementation, except for ERCOT, which is subject to
the exclusive jurisdiction of the Public Utilities Commission of Texas. The independent
market monitor within each RTO and ISO provides independent oversight over certain
market issues, including with respect to market concentration issues.
iii Contracts for sale of energy
The US electricity markets have a long history with bilateral power purchase and sale
contracting. Even where market participants are located within an applicable RTO or
ISO (i.e., bidding in the markets and scheduling flows with the RTO or ISO), market
participants often enter into bilateral energy and capacity contracts as a means of hedging
the volatility of market prices or providing a reliable source of supply. Bilateral contracts
can be in the form of physical purchases and sales or financial settlements. Some
contracting parties use standardised industry form agreements, such as those developed
by the Edison Electric Institute or the International Swap and Derivatives Association,
and others negotiate individualised contracts. Physical sales of energy, capacity and
ancillary services products in the wholesale market are subject to FERC jurisdiction and
must either be filed with FERC or reported through electric quarterly reports.
V
RENEWABLE ENERGY AND CONSERVATION
i Development of renewable energy
The United States does not have comprehensive policies regarding the development
of renewable energy. Rather, the federal government provides or has provided various
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targeted tax incentives and financing support programs, while a large number of states
have implemented renewable portfolio or clean energy standards and net metering, tax
incentives and installation cost rebate programs for distributed renewable generation
resources. There have been a series of unsuccessful efforts by Congress to mandate a
federal renewable or clean energy standard, most notably in the comprehensive
greenhouse gas (‘GHG’) cap and trade and clean energy legislation that passed in the
House of Representatives in 2009.
The federal government provides various tax incentives for renewable energy,
including:
a a production tax credit or ‘PTC’ (per energy generated) for wind, geothermal,
biomass and some other renewable energy resources (not including solar and fuel
cells);
b an investment tax credit or ‘ITC’ (based on qualified project costs) for a wide range
of renewable energy resources (including solar and fuel cells) and for combined
heat and power generation; and
c special accelerated depreciation rules that provided five-year depreciation for a
range of renewable energy resources placed in service from 2008 through 2012.
The PTC was first implemented under the Energy Policy Act (‘the EPAct’) of 1992,
and was most recently extended through 2013 (2012 for wind). The ITC was first
implemented under the EPAct of 2005 and was most recently extended until 2016.
Moreover, the American Recovery and Reinvestment Act (‘ARRA’) allowed taxpayers
eligible for the PTC to take the ITC in lieu of the PTC for projects installed in 2009
through 2013 (2009 through 2012 for wind). ARRA also allowed taxpayers eligible
for the ITC (including those taking the ITC in lieu of the PTC) to receive a cash grant
from the United States Treasury Department in lieu of the ITC for projects for whose
construction commenced by the end of 2011. The federal government estimates that
through early November of 2011 it provided approximately $9 billion in cash grants for
over 23,000 solar and large wind projects alone (with a combined generating capacity
of 13.5GW).
The DOE operates various loan guarantee programs for clean energy projects
established under Title XVII of the EPAct of 2005 and ARRA. ARRA provided DOE
with guarantee authority for commercial projects employing renewable energy systems,
electric power transmission systems, or leading-edge biofuels, and appropriations
to cover federal credit subsidy costs (i.e., loan loss reserves) of up to $2.5 billion for
projects that commenced construction by 30 September 2011. Accordingly, DOE issued
approximately $13 billion in full or partial guarantees for 19 renewable energy projects
(predominantly solar projects) between September 2010 and September 2011.
Twenty-nine states and the District of Columbia have renewable energy portfolio
standards requiring retail electric utilities to deliver a certain amount of electricity from
renewable or clean energy resources. These standards vary greatly across the states, both
in terms of their levels and target dates (generally between 10 percent and 30 percent
by no later than 2020) and what types of energy resources qualify (e.g., fuel cells, waste
energy, combined heat and power (‘CHP’), in-state versus out-of-state resources). Some
states also have specific requirements or ‘carveouts’ for specific energy resources such
as solar or distributed generation. Many of these states also allow utilities to comply
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with their standards through the purchase of tradable renewable energy credits (though
there are no national or regional markets for these credits because of differences across
states’ standards). More than 40 states and the District of Columbia have established
net metering policies that allow retail electricity consumers who own or host distributed
renewable generation resources (predominantly solar electric systems) to supply excess
generation to their retail electricity supplier in exchange for credits against their retail
electricity bills over 12-month and sometimes longer periods. Typically, generation
resources eligible for net metering arrangements cannot be sized at levels greatly in excess
of a retail consumer’s peak demand. A number of states offer various tax incentive and
rebate programs for distributed renewable generation resources. Most notably, California
provides a property tax exclusion for certain solar resources as well as installation cost
rebates or performance-based payments for solar and certain other renewable resources
(e.g., wind, fuel cells and CHP).
As discussed above, many of the federal tax incentive and financing support
programmes have ended or will soon end, though some of these programs could be
extended by Congress, as has been the case in past years, and has been proposed in
various legislation. However, given current fiscal concerns and related political
disagreements over the nature and role of federal financial support for clean energy,
the prospects for such legislation during 2012 remain unclear. At the same time, statebased
renewable portfolio standards, as well as net metering, tax incentive and rebate
programmes for distributed renewable generation resources appear poised to remain in
place for the foreseeable future (and as discussed in Section VI, infra, California not only
strengthened its renewable portfolio standard during 2011, it also took major steps to
begin implementing its own GHG cap and trade program, which is intended, in part,
to support greater deployment of renewable generation resources). Moreover, a number
of states are actively considering establishing, and in 2011 one state established, publicprivate
partnership clean energy financing entities to support deployment of renewable
energy and energy efficiency projects.
ii Energy efficiency and conservation
The United States has a limited set of comprehensive policies regarding promotion
of energy efficiency for electric appliances and energy efficiency standards for federal
buildings and properties. In addition, the federal government has various targeted grants
and financing support programs as well as tax incentives for energy efficiency investments.
A large number of states have similar types of programmes (many of which are
supported in whole or in part by funds provided by the federal government) and a large
number of states have energy efficiency portfolio standards, similar in concept to a
renewable energy portfolio standard, that require retail electric utilities to reduce their
total retail sales, peak retail sales, or both, by certain amounts by target dates. Some states
combine their renewable and energy efficiency portfolio standards. A number of states
have also combined their energy efficiency portfolio standards with retail utility rate
‘decoupling’ policies to allow utilities to recover of and on their fixed costs regardless of
reduced retail sales resulting from energy saving efforts. Certain states have implemented
or will soon implement financing support programs for end-use energy efficiency
investments, including ‘on-bill’ financing or repayment programmes that allow retail
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utilities or third parties to finance the full cost of end-use efficiency investments for
a retail utility customer and then recover of and on these investments through special
charges included on the customer’s retail utility bill. A similar type financing arrangement
is possible under federally authorised property-assessed clean energy (‘PACE’) bonding
authority for local governments, which use PACE bond proceeds to finance the upfront
costs of energy efficiency investments in homes and small businesses and have the loans
secured by an annual assessment on the home or business property tax bill, although this
programme has so far been limited to commercial properties because of federal home
mortgage insurance policies.
VI
THE YEAR IN REVIEW
FERC’s Order No. 1000 adopted significant reforms of FERC’s transmission planning
and cost-allocation rules established previously in Order No. 890. Order No. 1,000
seeks to address significant recent changes in the bulk power industry, including an
increased emphasis on integrating renewable generation and reducing congestion, by
implementing new policies to push transmission providers and planners to seek the most
reliable, efficient and cost-efficient solutions. The major reforms of Order No. 1,000
include:
a requiring each public utility transmission provider to participate in a regional
transmission planning process that produces a regional transmission plan and
regional and interregional cost allocation methods for planned projects;
b requiring each public utility transmission provider to amend its OATT to
describe procedures for considering transmission needs driven by public policy
requirements established by state or federal laws or regulations, such as state
renewable portfolio standards;
c removing from FERC-approved tariffs and agreements any federal right of first
refusal for incumbent utilities to build certain new transmission facilities; and
d improving coordination between neighboring transmission planning regions.
FERC’s Order No. 745 was adopted in 2011 to encourage demand responsiveness
through market pricing mechanisms. In Order No. 745 FERC required that the RTO
energy markets adopt market rules that treat demand reduction (i.e., ‘Negawatts’) in the
same way as supply alternatives (i.e., Megawatts) for the purpose of bidding into the
energy markets; however, the RTOs were still given flexibility as to how to implement
these market incentives. In April 2011, the California legislature approved Senate Bill 2,
which codified California’s ambitious renewable portfolio standard (‘RPS’) requirement
of 33 per cent by the end of 2020 (and 20 per cent by the end of 2013, and 25 per cent
by the end of 2016). Originally enacted in 2002, California’s RPS previously set a 20 per
cent requirement by 2010. The 33 per cent RPS requirement applies to both investorowned
and publicly owned utilities (which were not subject to the prior requirement).
Eligible technologies include solar, wind, geothermal, ocean wave, thermal and tidal
energy, fuel cells using renewable fuels, landfill gas, municipal solid waste conversion,
and certain biomass and hydroelectric resources. California also allows utilities to
comply with its standard through tradeable renewable energy credits, though a utility’s
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use of these credits is capped at 25 per cent of its applicable requirements. In related
developments, in September 2011, environmental regulators in California moved
forward with implementation of California’s GHG cap and trade programme previously
authorised under Assembly Bill 32 in 2006. This programme, the only GHG cap and
trade programme in the United States, will require California to reduce GHG emissions
to 1990 levels by 2020. This is of particular significance to the renewable generation
sector as when a first deliverer of electricity replaces conventionally sourced generation
with renewable generation, it will reduce its GHG compliance obligations. Moreover,
the cap and trade programme allows RPS-based renewable energy credits to be used
to satisfy GHG compliance obligations under the cap and trade programme (although
credits used in this way cannot also be used to be meet the RPS requirement).
Certain ISOs and RTOs that have forward markets for the sale of electric capacity
(distinct from the sale of electric energy) have implemented some version of a ‘minimum
offer price rule’, which imposes a minimum bid price for capacity to send appropriate
price signals for the future development of new generation and transmission facilities.
Some states located in those ISOs and RTOs have sought to use alternative non-market
mechanisms to encourage the construction of new electric-generating facilities in their
respective states through auctions for long-term power purchase arrangements. In these
state auctions (including in New Jersey and Maryland), the generator that wins the
auction must agree to offer into the capacity market at a price lower than its actual
costs, which would have the effect of decreasing market clearing prices for capacity. In
2011, some of these affected ISOs and RTOs (including PJM Interconnection LLC)
sought changes to their MOPRs in order to preclude the state auctions from artificially
suppressing capacity prices throughout the ISO or RTO. FERC has generally approved
these revisions, finding that if a generator entering the marketplace offers into the market
at a relatively lower price, not due to efficiency, but due to external non-market revenue
sources (i.e., through the state auction) that are not available to other potential new
entrants to the market, then prices will be artifically suppressed. There remain a variety of
state and federal regulatory and litigation proceedings on these matters that will remain
pending through 2012.
VII
CONCLUSIONS and OUTLOOK
Energy regulation in the United States is complex and multi-layered and will continue to
evolve for the foreseeable future. Competing economic and political interests (including
effects on ratepayers and taxpayers) cause conflict surrounding jurisdictional issues,
energy security, transmission system planning, cost allocation, renewable development
and integration and many other issues. The variety of energy industry participants and
regulators, as well as the geographical differences across the United States, can provide
an opportunity for the development of innovative policies, but such hegemony may also
lead to disjointed or overlapping regulatory obligations and may ultimately undermine
national energy policy.
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Chapter 28
Venezuela
Arnoldo Troconis 1
I
OVERVIEW
With estimated proved crude oil reserves at 31 December 2011 of approximately 297.57
billion barrels, 2 Venezuela remains one of the most important oil-producing countries in
the world and a focus of interest for the oil and gas business community.
Despite the latest trend in policies implemented by the government, which
could have, to some extent, discouraged private participation in oil and gas activities,
companies in the oil and gas sector still monitor the developments of the market for
potential new projects or participation. In any case, these new policies have created new
spaces for participation that have been filled by new players that did not traditionally
participate in the Venezuelan oil and gas market.
The trend in government policy is well known to people familiar with the world
oil and gas markets. The Venezuelan government has taken control of upstream oil and
gas activities by modifying a previous oil and gas legal framework (in force prior to
2002) into one under which the government either directly (or with a minority private
participation) carries out upstream oil and gas activities. Additionally, in May 2009, the
government expanded such policy reserving the main activities concerning oil and gas
services to the state.
1 Arnoldo Troconis is a partner at D’Empaire Reyna Abogados.
2 ‘A recent announcement made by the Venezuelan minister of energy and petroleum stated
that Venezuela’s proven oil and gas reserves rose by 2.158 billion barrels to 297.57 billion
barrels at the end of 2011. The announcement of the minister specifies that over half of the
new reserves, 1.2 billion bbl, came from traditional crude producing areas such as Barcelona,
Barinas, Maracaibo, Maturin and Cumana and from condensates at the offshore Cardon IV
and Mariscal Sucre gas fields. An additional 948 million bbl of heavy oil reserves were added
from the Orinoco belt.’ Energy Intelligence, Oil Daily, 20 March 2012.
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Venezuela
The modification of the oil and gas legal framework in 2002, along with
the increase in oil prices during this period, caused the government to begin a long
process aimed at adapting the then-existing contractual arrangements to becoming one
appropriate for the new legal framework.
Through a migration process, the Venezuelan government ‘negotiated’ by 2006
and 2007 the conversion of operating service agreements and association agreements for
majority government-owned joint ventures. More specifically, in 2005, the Ministry of
Petroleum and Mining (‘the MEP’) instructed the conversion of the existing operating
agreements to a regime of joint ventures, in which Petróleos de Venezuela SA (‘PDVSA’), 3
through its subsidiary CVP, was to hold between 60 per cent and 80 per cent stock
ownership. During 2006, 19 operating agreements were converted into joint ventures,
and exploration and production in new areas (profit-sharing agreements) 4 and strategic
associations to produce crude oil in the Orinoco Belt 5 (encompassed as association
agreements) were converted into joint-venture projects controlled by the government. 6
As a consequence of this process, several private companies remained as minority
private participants in such joint ventures. In effect, the model contracts developed to
implement such migration were signed by several oil and gas companies such as BP,
Chevron, Shell, Total, Statoil, Eni, Petrobras, Repsol, CNPC, Sinopec, Anadarco,
Hocol, Perenco, Tecpetrol, Compania General de Combustibles, Teikoku and Harvest
Natural Resources. Only Exxon Mobil and Conoco initiated arbitration proceedings
3 PDVSA is the largest vertically integrated company in Latin America and the fourth largest
vertically integrated oil company in the world, measured by a combination of operational data,
including volume of reserves, production, refining and sales. PDVSA carries out exploration,
development and production operations in Venezuela as well as the selling, marketing, refining,
transport, infrastructure, storage and shipping operations in Venezuela, the Caribbean, North
America, South America, Europe and Asia. PDVSA indirectly owns 100 per cent of CITGO,
a refiner and marketer of transportation fuels, petrochemicals and other industrial oil-based
products in the United States. PDVSA has a refining capacity of approximately 3 million
barrels per day (or mmbpd), and other feedstock in Venezuela and abroad in a number of
products, including gasoline, diesel, fuel oil and jet fuel, petrochemicals and industrial products,
lubricants, waxes and asphalt (Petroleum Intelligence Weekly).
4 The following are the joint ventures operating the former profit sharing agreements: Petrolera
Paria SA, operating the Golfo de Paria Este project; Petrosucre SA, operating the Golfo de Paria
Oeste project; Petrolera Güiria SA, operating the Golfo de Paria Central project; and La Ceiba
field is operated directly by PDVSA Petróleo.
5 On 26 February 2007 Decree 5,200 established the timeline and general guidelines for the
transfer of such association agreements (previously controlled by private entities) to joint
venture projects controlled by the government. Under this decree, the associations of Hamaca,
Sincor and Cerro Negro became joint ventures.
6 The current joint ventures operating the Orinoco Oil Belt are: Petropiar SA joint venture,
operating the Hamaca project; Petrocedeño SA joint venture, operating the Sincor Project;
Petromonagas SA joint venture, operating the Cerro Negro Project; and Petrolera Sinovensa SA
(Petrosinovensa) joint venture, operating the Carabobo.
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Venezuela
against PDVSA and Venezuela as a result of the migration process. Further application
of new laws by the government, such as the reserve of the oil and gas services sector led
to more arbitration proceedings. 7
In addition to controlling the oil and gas activities, the government has changed
the focus of the state-owned company PDVSA by broadening its scope of activities
outside the core oil and gas business activities. In effect, PDVSA has been assigned the
task of not only directly exploiting the oil and gas industry, but also contributing to
the socio‐economic development of Venezuela by implementing social programmes of a
completely different nature. Such activities include the import of food, food distribution,
funding the purchase of electricity companies or projects funding infrastructure and
agriculture, including roads, health and education.
Additionally, PDVSA is now required to make significant financial contributions
to the National Development Fund (FONDEN), 8 which have had an important effect
on its cashflow. Specifically, according to Article 5 of the Hydrocarbons Law (defined
below), PDVSA’s revenues must be used to finance health and education, to create funds
for macroeconomic stabilisation and to make productive investment to the benefit of
the welfare of the Venezuelan population. For example, PDVSA contributed a total of
$3.5 billion in 2009, $7 billion in 2010 and a total of $30 billion in 2011 to social
development. These contributions were in addition to taxes and dividends paid by
PDVSA annually to the state, as well as the social projects funded by the company. As
a consequence, PDVSA’s new obligations have given rise to debate on whether PDVSA
should engage in activities that give preference to the government’s objectives rather than
the economic and business objectives of the company. 9
Alongside this debate, PDVSA has reflected its future plans in the oil and gas
sector in the Siembra Petrolera Plan (Oil Sowing Plan) 2010–2015 describing its
7 Currently, Venezuela has six oil related arbitration proceedings before ICSID: Eni Dación BV
v. Bolivarian Republic of Venezuela (ICSID Case No. ARB/07/4); Opic Karimun Corporation
v. Bolivarian Republic of Venezuela (ICSID Case No. ARB/10/14); The Williams Companies,
International Holdings BV, WilPro Energy Services (El Furrial) Limited and WilPro Energy
Services (Pigap II) Limited v. Bolivarian Republic of Venezuela (ICSID Case No. ARB/11/10);
Mobil Corporation and others v. Bolivarian Republic of Venezuela (ICSID Case No. ARB/07/27);
ConocoPhillips Company and others v. Bolivarian Republic of Venezuela (ICSID Case No.
ARB/07/30); and Universal Compression International Holdings, SLU v. Bolivarian Republic of
Venezuela (ICSID Case No. ARB/10/9) http://icsid.worldbank.org/ICSID/Index.jsp.
8 FONDEN is a special fund that was created by the government of Venezuela in 2005 as a
corporation to finance and manage investment projects, public education, health care and
other welfare projects in Venezuela, to promote the economic and social development of the
country. PDVSA also contributes to the FONDEN through mandatory transfers required
under the Windfall Tax Law.
9 PDVSA was originally created in 1975 to coordinate, monitor and control all operations related
to hydrocarbons At such time PDVSA was exclusively dedicated to the oil and gas business, not
significantly subject to political or social endeavours.
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intended projects and vision for the future development of the oil and gas industry in
Venezuela. The list of the most important projects includes:
a PDVSA’s intention to focus on areas that have been already explored and that are
currently producing crude oil (with respect to exploration of condensate and light
and medium crude oil);
b the development of the Orinoco Oil Belt Magna Reserves; 10
c the performance of certain investments for production growth in mature areas; 11
d the expansion of the Orinoco Oil Belt Production;
e the development of major projects in refineries; 12
f the development of the gas sector; 13 and
g the development of certain infrastructure projects. 14
II
REGULATION
The Venezuelan constitution establishes that mineral resources and hydrocarbons within
the country’s territory (including the territorial sea, exclusive economic zone and in the
continental shelf) belong to the state. 15 Therefore, title to hydrocarbons passes at the
wellhead to the corresponding operating company namely, PDVSA Petróleo SA (PDVSA’s
Venezuelan operating subsidiary) or the corresponding joint venture company. 16
10 Pursuant to PDVSA’s disclosed information, there are 1.36 billion barrels of original oil on site
(OOOS) in the Orinoco Oil Belt.
11 PDVSA intends to invest in mature areas with a view to achieve a crude oil production capacity
of 4,481 million barrels per day (‘mbpd’) by 2015. Such projected production for the period
leading up to 2015 would be divided as follows: 2,205 bpd from areas where PDVSA is the sole
operator, 555 mbpd from joint ventures producing light and medium oil and 970 mbpd from
LPG Liquefied Petroleum Gas operations. PDVSA intends to obtain the remaining 661 mbpd
of the 4,481 mbpd crude oil production capacity projected for 2015 from the expansion of
PDVSA’s operations in the Orinoco Oil Belt, which PDVSA plans to implement by developing
its extra-heavy crude oil reserves, including new upgrading facilities and pipelines to terminals.
12 PDVSA intends to expand its refining capacity from approximately 3.0 billion barrels per day
(‘mmbpd’) (1.3/1.7 mmbpd Venezuela/overseas capacity) to 3.2 mmbpd by 2015 (1.4/1.8
mmbpd Venezuela/overseas capacity).
13 PDVSA has plans to develop its onshore and offshore gas reserves with third-party participation
under the framework of the Gas Law.
14 PDVSA is implementing an infrastructure program focused on multiple projects with the
aim of securing the development of crude oil and gas reserves. This programme includes the
building of about 9.3 million barrels of oil storage capacity, three additional loading docks,
approximately 650 kilometres in oil pipelines, four new distribution facilities, the expansion of
existing gas pipelines and building new pipelines.
15 Article 12 of the Venezuelan Constitution.
16 The Constitution provides that for ‘reasons of economic and political sovereignty and national
strategy’ Venezuela shall retain all of PDVSA’s stock or any other entity to be incorporated to
handle the petroleum industry (Article 303 of the Hydrocarbons Law).
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Oil and gas activities are regulated only by the federal government; neither the
state, nor municipal governments can regulate or tax oil and gas activities. Crude oil
and gas at the wellhead is regulated in the Organic Hydrocarbons Law and regulations
thereunder. Gaseous hydrocarbons including liquid hydrocarbons and non-hydrocarbon
components contained in gaseous hydrocarbons, as well as gas resulting from the refining
of oil are regulated in the Organic Gaseous Hydrocarbons Law (‘the Gas Law’) and
regulations thereunder. 17
i The regulators
The MEP is the entity with oversight over hydrocarbon activities (petroleum or gas). It
has broad powers and scope of authority, and handles the relationship with the operating
companies. In this regard the MEP creates and follows up on the policies, planning,
performance and oversight of hydrocarbons activities. Such powers entail supervision of
matters such as development, conservation, use and control of such resources, including
the study of markets, analysis and fixing of the prices of hydrocarbons and their products. 18
Moreover, the MEP is the entity in charge of all matters related to the administration
of hydrocarbons; therefore, it has the power to inspect all works and related oil and
gas activities, including the auditing and review of the accounting corresponding to
operations generating taxes, charges or contributions established in the law. 19
Enagas, which is a specific national gas entity, has some oversight and regulatory
powers over the gas sector, but it is mainly an advisory and technical body. Enagas is
a functionally autonomous administrative body (with no separate legal personality),
directed by a board of five members. Its most important objectives include:
a promoting and supervising the development of the transport, storage, distribution
and commercialisation of gas;
b supervision and supply of information to the MEP on the existence of
non‐competitive conducts, monopolies or discriminatory conducts;
c proposing to the MEP for its approval the establishment and modification or
limits of the regions for the distribution of gas;
d promoting the development of secondary markets;
e proposing to the MEP for its approval conditions to qualify companies that may
perform the transport, storage, distribution and commercialisation of gas;
f proposing to the MEP for its approval fair tariffs for transport and distribution;
g supervising the free access to the systems of transport, storage and distribution of
gas;
h promoting the efficient use and application of best practices in the gas industry,
and its use as a fuel or raw material;
i oversight of the rights and duties of participants in the gas industry; and
j advising the gas industry on the correct application of the basis and formulae for
the calculation of gas prices and tariffs.
17 Article 2 of the Gas Law.
18 Article 8 of the Hydrocarbon Law.
19 Article 6 of the Gas Law.
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The MEP fixes the prices for final consumers of gas hydrocarbons jointly with the Ministry
of Commerce. 20 The MEP is empowered to determine the prices of hydrocarbon gases
from the production and processing centres, taking equitable principles into account. 21
Only Enagas may calculate the basis for the determination of these tariffs. The tariffs for
small consumers are the sum of the price of acquisition of gas, the transport tariff and
the distribution tariff. 22
Tariffs for storage, transportation and distribution services must be fixed subject
to certain principles and guidelines. Such tariffs must guarantee efficiency of operations
and sufficient income to satisfy adequate operational and maintenance costs, as well as to
cover taxes, depreciation, amortisation of investments, and a reasonable profit. 23
Profitability has to be reasonable compared to the profitability of other activities
with similar risks and in light of the efficiency of the services provided. Tariffs must also
take into account the specifics of the services provided, such as geographical location,
distance between sale and production points, and other conditions to be defined in the
regulations. Tariffs should allow the lowest possible cost for consumers while at the same
time assuring a stable supply for the market. 24
Companies marketing methane are entitled to request from the MEP the approval
of price agreements with their clients (previously agreed by the parties) provided that the
contracts need to have been entered into to supply gas for industrial use, for a specific
term and for consumers that require a long-term price scheme. 25
ii Regulated activities
Upstream activities: petroleum
On 13 November 2001, President Chavez issued the Hydrocarbons Law. 26 The 2001
Hydrocarbons Law was partially amended by the National Assembly on 16 May 2006. 27
Pursuant to the Hydrocarbons Law, oil production activities (‘primary activities’) 28 can only
be carried out by the state, companies wholly owned by the state, or joint venture or mixed
companies (‘JVs’) in which the state retains control of its decisions through the ownership
of more than 50 per cent of its capital. 29 The Hydrocarbons Law considers the exploration
for oil, production, gathering, transportation and initial storage as primary activities.
20 Resolution 450, dated 6 November 1998, contains the specific formulae to determine methane
prices for domestic, commercial, industrial and electric generation customers.
21 Id, Article 12.
22 Id
23 Article 13 of the Gas Law.
24 Id.
25 Article 3 of Resolution 450, dated 6 November 1998.
26 Decree-Law 1510 published in the Official Gazette No. 37,323 dated 13 November 2001.
27 Originally published in the Official Gazette No. 38,443 dated 24 May 2006, republished with
corrections in the Official Gazette No. 38,493 dated 4 August 2006.
28 Pursuant to Article 9 of the Hydrocarbons Law, ‘primary activities’ include exploration of oil
fields, extraction of oil in its natural state, and initial recollection, transportation and storage.
29 Article 22 of the Hydrocarbons Law.
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By law, companies performing primary hydrocarbon activities are considered
‘operating companies’. 30 Therefore, upstream petroleum-related activities are reserved to
the state and private participation is limited.
The rights to perform primary activities are granted by a procedure under which
the Executive, through the MEP, assigns the geographical area where the primary
activities will be developed. The Decree is then issued by the transfer by the Executive to
the operating company of the rights to perform primary activities.
In contrast, the creation of the JVs and the conditions under which they will
perform primary activities require the approval of the National Assembly, including
further modifications to such conditions. 31
The conditions under which the JVs will perform the primary activities must at
least include the following: (1) a maximum term of 25 years; (2) a description of the
area where the activities will be performed; 32 (3) the land and equipment to be kept
in good conditions and working order to be delivered to the state free of liens, in case
of termination of the rights for any reason; and (4) that any dispute arising from the
performance of the activities will be decided by the courts under Venezuelan law. 33
Under Article 57 of the Hydrocarbons Law, the marketing of natural hydrocarbons
can be performed only by wholly state-owned companies. Therefore, JVs producing
‘natural hydrocarbons’ can only sell their production to PDVSA Petróleos SA.
Midstream and downstream activities
In contrast with the legal treatment of upstream activities, midstream or refining activities
may be legally carried out by private companies, not subject to government control. The
performance of such activities would require the granting of a licence, however, although
these activities do not have limitations on private investment, existing refineries and
facilities were reserved to the state, 34 therefore these private investments would be feasible
only in new facilities.
Currently, there are no private entities (e.g., entities that are majority-owned
by private parties) undertaking refining activities in Venezuela and it is not currently
anticipated that there will be any private refineries in the foreseeable future. In effect, the
government seems intent on pursuing a policy in which most of its future oil and gas
plans will be carried out through JVs under its control.
The marketing of hydrocarbon by-products is also open to private investment
(including foreign investment) without limitation; however, the Hydrocarbons Law sets
out that the Executive may determine by Decree that the marketing of by-products can
be performed only by wholly state-owned companies. This power of the government to
30 Id.
31 Provided such modifications have the favourable opinion of MEP and the Permanent
Commission of Energy and Mines of the National Assembly (Article 33 of the Hydrocarbons
Law).
32 Article 23 of the Hydrocarbons Law.
33 Article 33 of the Hydrocarbon Law.
34 Id, Article 10.
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reserve any product at any time causes clear uncertainty with respect to any planned or
proposed investment by private parties to market by-products.
The supply, storage, transport, distribution and sale of hydrocarbons by-products
require a permit issued by the MEP.
On 4 September 2008 the Organic Law to Reorganise the Internal Market of
Liquid Fuels was passed, which sets out that only to the state may act as intermediary for
the supply of liquid fuels between PDVSA and the entities selling the fuel. The transport
of liquid fuels is also reserved to the state.
Gas activities
The Gas Law governs all exploration activities for non-associated gas and exploitation of
such reservoirs; collection, storage and use of non associated gas, as well as associated gas
(with oil and other fossils); and the processing, industrialisation, transport, distribution,
internal and external commerce of such gases. Also, the Law regulates all matters
related to liquid hydrocarbons and non-hydrocarbon components contained in gaseous
hydrocarbon production, as well as the gas derived from the process of oil refining. In
view of the broad scope of the Gas Law, it could be concluded that only associated gas at
the wellhead falls within the scope of the Hydrocarbons Law.
Gas-related activities can be performed directly by the state; state-owned
companies or private entities, with no need for state participation. Therefore, the gas
sector is totally open to private participation.
Exploration and exploitation of non-associated gas require a licence; any other
gas-related activities by private parties (such as processing, industrialisation, storage,
transportation, distribution or commercialisation of gas) require a permit. The MEP is
in charge of granting the licences or permits to entities carrying out gas-related activities.
Such licence is subject to inclusion of the following:
a the description of the project indicating the destiny of the hydrocarbons;
b a maximum term of 35 years, subject to extension by the parties for not more
than 30 years;
c a term of five years to comply with exploration and compliance with programmes;
d description of the area;
e
f
g
special contributions to the state;
land and equipment to be kept in good condition and working order to be
delivered to the state free of liens, in case of termination of the rights for any
reason; and
any dispute arising from the performance of the activities will be decided by the
courts under Venezuelan law.
The MEP (through a resolution) will determine the areas where the exploration and
exploitation of non-associated gas may be carried out.
The permits are similar to the licences (except for those not applicable to them
such as compliance with exploratory programmes or the description of an area). The
permits for entities involved in the industrialisation of gas or commercialisation of
liquefied petroleum gas are not subject to the 35-year limitation or to returning the
assets at the end of the term.
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Rights granted under the licence can be assigned, provided the MEP issues its prior
approval, but no foreclosures or liens can be created on licences. Additionally, licences
may be revoked for non-compliance with the exploration programme, assignment
without prior approval or application of the causes for termination under the licence.
The permits may be revoked by the MEP if transferred without its previous
authorisation or non-compliance with the programme of execution by the government.
Oil and gas services
The Organic Law that reserves to the Venezuelan State assets and services related to
primary oil activities (the ‘Oil Contractor’s Law’), reserves to the state the assets and
services connected to the primary oil activities previously carried out directly by PDVSA
and its affiliates, and which had been previously outsourced to third parties.
Specifically, the assets and services subject to the Oil Contractor’s Law are water,
steam and gas injection facilities that enhance reservoir recovery; gas compression;
and assets linked to activities in Lake Maracaibo such as personnel, submarine and
maintenance transportation boats, rig boats, diesel, industrial water and other supplies;
transportation boats, tug boats, underwater cable, ports and levies, among others.
iii Transfers of control and assignments
Under the Hydrocarbons Law, licences are subject to revocation in case of assignment,
creation of lien or execution without the authorisation of the MEP. Assignment, transfer,
or liens on licenses require prior approval of the MEP. The sale of shares of the private
participant is subject to prior approval by the MEP.
Under the Agreement of the National Assembly Approving the Terms and
Conditions for the Creation and Functioning of JVs, it is set out that with the exception
of transfers to an entity that is directly or indirectly owned by the parent companies,
none of the parties can transfer, assign or create a lien on its shares on the JV without the
prior written consent of the Minister.
III
TRANSMISSION/TRANSPORTATION and DISTRIBUTION
OF SERVICES
i Vertical integration and unbundling
The Gas Law prohibits vertical integration. Therefore, the same entity cannot
simultaneously carry out or control two or more of the activities of production, transport
or distribution in the same region. The MEP can authorise the same entity to carry out
more than one of the referenced activities provided the viability of the project in question
requires it, in which case the authorised person must establish separate accounting
systems for the separate activities.
ii Transmission/transportation and distribution access
Companies carrying out the storage, transportation and distribution of hydrocarbon
gases and their by-products must allow other companies who also carry out such storage,
transportation and distribution to use their facilities when these facilities have spare
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capacity. Such use is subject to contractual arrangements as the parties may agree. If the
parties cannot agree on conditions, the MEP will establish them.
Pursuant to the Gas Law, this open-access obligation does not extend to producers,
traders or major end users; however, the Gas Law does not prohibit the storage,
transportation and distribution companies from buying and selling gas in addition to
providing service. Therefore, producers, gas traders and major users have no explicit right
to open access.
IV
ENERGY MARKETS
The gas industry in Venezuela directly depends on the cycles of oil business, given that
more than 90 per cent of Venezuela’s gas reserves are associated with crude. 35 The purpose
of the Gas Law was to attempt to modify the structure of the Venezuelan gas market,
but the fact that the varous stages are in the hands of affiliate companies of PDVSA
influenced the enforcement of the law, and hence the market has not yet changed as
intended.
In effect, the government is involved in the exploration and production business
through a vertically integrated company (PDVSA Gas). This company engages in gas
exploration and production activity and the processing of gas production, as well as the
transportation and marketing of gas in the domestic market. PDVSA Gas processes gas
produced by the eastern and western exploration and production divisions of PDVSA,
receiving all the remaining gas after consumption for PDVSA’s operations, for transport
and marketing in the domestic market. PDVSA’s wholly owned subsidiary CVP manages
offshore natural gas projects.
The gas industry is currently integrated in a vertical structure, with the exception
of certain participants, which include:
a producers (PDVSA E&P, Ypergas, Copa Macoya and Barrancas);
b transportation (PDVSA Gas);
c local distribution companies (PDVSA Gas Comunal, Domegas, Sagas, Tigasco);
and
d end users (industrial, power, iron and steel, and residential.
The Eastern Basin is the largest producer region in Venezuela, where the gas production
is mainly concentrated. For a long time, the largest gas producer was the Maracaibo
Basin in the west of the country, but many of its reservoirs have been depleted. As a
result, there is a critical lack of gas in the western region, reaching such levels that imports
from Colombia have provided an important share of the gas supply to these consumers,
mainly through the TransCaribbean pipeline from Puerto Ballena–Bajo Grande.
35 Venezuela produced in 2006 only 2.6 trillion cubic feet (‘TCF’), of which the oil industry
consumed 71.1 per cent of Venezuela’s natural gas production, with the largest share of that
consumption for injection to enhanced oil recovery (1.1 TCF equivalent to 60 per cent of that
consumption. ‘Venezuela natural gas market: a project for its growing’ (Marco González).
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Most of the gas destined for the market is produced by PDVSA, with few exceptions
that include Yucal–Placer Norte, Barrancas Block and Quiriquire Deep. Several factors
affect gas supply in Venezuela, including the important fact that the associated gas
depends on the fluctuations of the oil business. The geographical conditions also affect
supply, since the production of gas available for the domestic market is concentrated in
the eastern region, and the western region has a gas shortage, as previously detailed; not
to mention PDVSA’s influence as sole supplier of the gas industry. Finally, the price of
gas at the wellhead for producers is not high enough to create an incentive.
Oil has widely taken priority in the Venezuelan energy matrix, followed by the gas
industry. Hydroelectricity takes the third place in production terms, while coal remains
in a lowly position. Gas demand is affected by the domestic market, as all gas produced
in Venezuela is allocated to this group of consumers.
The domestic market in Venezuela is composed of the oil industry, the industrial
sector, and the electric, petrochemical and residential sectors. Throughout the past
decade, the oil industry has retained its position as the greatest consumer, followed by
gas power generation, the industrial sector and the petrochemical sector. The residential
sector is consolidated with a minimum percentage compared with total production.
The transportation stage is likewise controlled by PDVSA, which owns more than
4,000 kilometres of pipeline for the transportation of gas. The effect of the government’s
regulation of this sector has largely affected the price variables, hindering it from
achieving further development.
V
RENEWABLE ENERGY AND CONSERVATION
Even though Venezuela has 2,718 kilometres of coastline with wind speeds blowing at
an average of 8.9 metres per second, which could easily host large-capacity wind power
generation systems, renewable energy developments have largely been ignored due to the
focus on oil and gas production.
Only one project in the Paraguaná peninsula of the state of Falcon has progressed
to the first stages, financed by PDVSA. The potential for private investment has been
discussed as many agree that only through private investment will Venezuela speed up
to match the pace of other Latin American countries, where many projects are already
being developed. Allowing private investment for renewable energy projects would be
a strategically wise decision for the Venezuelan government, as it would be able to sell
more of its oil to the international markets rather than using it for domestic purposes.
The installation of a renewable energy infrastructure will not be an easy task for
a country that has not yet developed a regulatory framework for the matter or attracted
the proper investment, making it more of a long-term solution.
Vi
THE YEAR IN REVIEW
As we discussed, the migration processes to JVs gave rise to several conflicts, including
the case initiated by Mobil Cerro Negro Ltd before the ICC in New York in 2008 and
the Exxon claim against Venezuela, initiated in 2007 before ICSID in Washington, DC
– one of the most relevant cases brought against PDVSA.
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The Mobil Cerro Negro Ltd dispute arose from an association agreement that was
entered into between PDVSA and Mobil Cerro Negro Ltd. The project consisted of an
agreement for the activities relating to extra-heavy crudes in the Cerro Negro Reservoir
situated in the Orinoco Oil Belt. The activities included extraction, transportation,
upgrade and refining of the crudes. In this agreement, PDVSA granted a bond in favour
of Mobil Cerro Negro Ltd, which alleged that PDVSA should indemnify them for the
discriminatory measures taken by the Venezuelan government.
Mobil Cerro Negro Ltd’s arguments focused on the fact that the government had
enacted discriminatory measures that gravely affected their long-term fiscal situation.
According to Mobil Cerro Negro, PDVSA breached the association agreement due
to lack of compensation for the discriminatory measures, absence of good faith in the
negotiations and a lack of a compensating indemnity for the discriminatory measures.
Compensation was requested by Mobil Cerro Negro Ltd, to be calculated on the terms
of the association agreement, interest, costs and other fair indemnities.
According to PDVSA, the claims were not valid under the dispositions of the
association agreement, and the breach derived from a decision of the government, hence
the parties were not responsible.
PDVSA alleged that Mobil did not have a legal basis to claim discriminatory
measures since the government measure did not fall within such definition under the
association agreement. Moreover, they insisted that Mobil did not comply with the
necessary conditions to make such claims. PDVSA also argued that the association
agreement included that the parties would be free from any responsibility if the breach
was caused by governmental orders or decisions.
The amounts claimed generated even more controversy, as PDVSA alleged that
even if there were a debt, the amount would not even be a fraction of what Mobil
was claiming. PDVSA requested the Tribunal to grant certain claims for the harassment
campaign it alleged it suffered, plus reimbursement for sold products and operations
related to the project finance.
In January 2008 granted were measures in England by the Royal Court of Justice
Queen’s Bench Division Commercial Court of England and Wales, freezing the assets of
PDVSA in England. Two months later, the same court revoked the measure, which had
frozen $12 billion of PDVSA’s assets.
The ICC arbitration court made a decision in December 2011, affirming
its jurisdiction over the association agreement, and confirming the existence of
discriminatory measures causing a materially adverse impact as defined in the agreement.
Moreover, they declared PDVSA-CN and PDVSA responsible for the discriminatory
measures under the association agreement.
PDVSA-CN and PDVSA were declared jointly and severally liable to pay
Mobil $12.68 million for 2007 and $894.9 million for the period 2008–2035, a
total of $907.581 million. This amount was subject to a set off arising from PDVSA’s
counterclaim, which resulted in a net amount of $746.9 million.
In the past year, PDVSA has signed agreements with Eni and Repsol for gas
purposes, with the objective of buying gas for the Perla field in the Gulf of Venezuela,
the country’s largest gas field. Thanks to these agreements, production in Venezuela will
increase to 33 billion cubic metres by 2016, further reaching to 44 billion cubic metres
by 2021.
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Venezuela
VIi
CONCLUSIONS and OUTLOOK
It seems that PDVSA will continue to be required by the central government to fund
and manage the social-related activities it currently undertakes. If so, it seems likely that
PDVSA will need to continue to seek partners to help it fund, manage and operate the
development of its massive reserves.
Consequently, Venezuela remains a very important oil and gas country and
investors will continue to monitor opportunities in the country; however, the result of
arbitrations against PDVSA and Venezuela need to be reviewed, including their impact
on future investments in Venezuela.
‘Below ground’ risks in Venezuela are substantially lower than those of other more
up-and-coming oil players such as Angola and Brazil. ‘Above ground’ risks in Venezuela
may start to be mitigated out of PDVSA’s need for new partners and financing.
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Appendix 1
About the authors
Masood Afridi
Afridi & Angell
Masood Afridi is a partner at Afridi & Angell specialising in the areas of infrastructure
and project finance, corporate and commercial, and energy law.
After working as an associate at the New York offices of the law firm of Sidley &
Austin, he joined the Dubai office of Afridi & Angell in 1993. For several years, he has
been a frontrunner in Pakistan’s energy sector, and has participated in the development of
numerous thermal and hydel power projects in the country. He has also been nominated
from time to time to resolve other global issues with the power purchaser on behalf of
the industry.
Acting in the capacity of project developer’s lead counsel, Mr. Afridi has concluded
transactions with a cumulative value of over $3 billion spread over several project finance
transactions.
Mr Afridi has an LLM in International Business and Trade Law from Fordham
University (1990) and an LLB from University of Bristol. At Fordham University, Mr
Afridi received the Edward J Hawke Prize for graduating with the highest grade point
average in his class.
Lukman Sheriff Alias
Zul Rafique & Partners
Lukman Sheriff Alias is a partner in the Energy & Utilities practice group. He holds a
bachelor of laws (first class) from the International Islamic University Malaysia (IIUM),
a master of laws in commercial law from Cambridge University and a postgraduate
diploma in Islamic banking and finance from IIUM. He was the recipient of the IIUM
Best Overall Student Award and Tunku Abdul Rahman Foundation Gold Medal Award
and is a fellow of Cambridge Commonwealth Society. He was called to the Bar in 1993
and has extensive experience in advising on large-scale privatisation, infrastructure and
construction projects.
357

About the Authors
He was formerly the general manager of one of the largest Islamic funds in
Malaysia in the legal and enforcement division and has advised on various Islamic
investment and financing matters. Previously, he sat as a member on the Bank Negara
Law Review Committee for Islamic Banking and Finance.
He has been involved in various notable energy projects and advised on various
types of energy-related project documents including power purchase agreements for
Malaysian and overseas power projects. His experience includes acquisition and operation
of coal mines projects.
Mr Alias has also advised the Malaysian government in respect of the water
services industry in Malaysia. He was involved in the drafting of the Constitutional
Amendment Act 2005, Water Services Industry Act 2006 and the National Water
Services Commission Act 2006.
Per Conradi Andersen
Kvale Advokatfirma DA
Per Conradi Andersen is a partner at Kvale in Oslo. He holds an LLM in European legal
studies and is an admitted attorney to the Supreme Court. He has been engaged in the
electricity sector from 1990, first as a senior executive officer at the Royal Ministry of
Petroleum and Energy, then after two years as a judge, for the past 17 years as a lawyer
in Oslo-based law firms. He has written a book about the Norwegian Energy Act and
several articles in various publications.
Hans Andréasson
Mannheimer Swartling
Hans Andréasson heads Mannheimer Swartling’s energy industry group. He has been
active in the sector since the early 1990s and has extensive experience in the production,
distribution and marketing segments and has represented a variety of industry actors,
both public and private, in acquisitions, divestitures, restructurings and has also advised
on key regulatory issues for the energy sector. Mr Andréasson is also a member of the
corporate commercial, private equity, and mergers and acquisition practice groups. He
studied at the University of Stockholm (LLM, 1992). After service in the Swedish courts,
Mr Andréasson joined Mannheimer Swartling in 1994 and became a partner in 2001.
Fabio Ardila
Gómez-Pinzón Zuleta
Fabio Ardila is member of the firm’s natural resources practice. Admitted in 2011, he
graduated from the Universidad de los Andes.
Patricia Arrázola-Bustillo
Gómez-Pinzón Zuleta
Head of the corporate and the energy and mining practice, Patricia Arrázola-Bustillo
currently acts as external legal counsel to many well-known multinational companies
that operate in Colombia. She graduated in law from Universidad del Rosario and
completed a graduate programme in corporate law at Universidad Javeriana. She has
358

About the Authors
written several articles that address important topics under the energy and corporate laws
and has participated in many panels discussing relevant issues in those areas. Ms Arrázola-
Bustillo is currently recognized as a key practitioner in the corporate law practice and in
the energy practice by several international legal publications.
Eliza Bartlett
Minter Ellison
Eliza Bartlett is a commercial and regulatory lawyer with specialist experience in the
energy sector. She advises on the commercial and regulatory aspects of major energy
transactions, including gas, electricity and renewable projects.
Ms Bartlett experience has included two lengthy secondments as in-house counsel
to a state-based government department responsible for energy regulation in Victoria
and an Australian publicly listed energy company.
Haroon Baryalay
Afridi & Angell
Haroon Baryalay is an associate at Afridi & Angell, having jointed the firm in 2011.
Prior to joining Afridi & Angell, Mr Baryalay worked at Haidermota & Co. in Pakistan,
from 2006. His practice areas include project finance, corporate and commercial, and
the energy sector.
Mr Baryalay has an LLM from Harvard Law School (2005), an LLB from the
University of London (2004) and a BSc in Economics from the Lahore University of
Management Sciences (LUMS) in Pakistan (2001).
Elisabeth Blunsdon
Hogan Lovells
Elisabeth Blunsdon works in the infrastructure and project finance, and energy practices
at Hogan Lovells. She has extensive experience in energy regulation, M&A, derivatives,
structured trading and commercial issues in the energy sector. Ms Blunsdon has advised
project developers, multinational energy and utility companies, investment banks,
commodities trading houses, hedge funds and governments. She has spent several
extended periods on secondment to in-house legal departments in the energy sector. She
has particular experience in the regulation, operation and optimisation of energy assets
in the gas, renewables, power and nuclear sectors.
Ms Blunsdon has an MA from Corpus Christi College, University of Cambridge,
and is a member of the Law Society, Association of International Petroleum Negotiators
and the Institute of Engineering and Technology. She speaks English and French.
Martha Brinkman
Stek
Martha Brinkman is a senior competition and regulatory attorney. She litigates and
advises on European and Dutch competition law issues, public procurement law and
sector-specific regulation. Ms Brinkman is co-author of the section on energy regulatory
359

About the Authors
developments in the Netherlands Journal for Energy Law. The Legal 500, 2012 edition,
recommends her as a leading energy lawyer.
Evgeny Danilov
Goltsblat BLP
Evgeny Danilov is an expert in civil law and legal regulation of subsoil use and has
been engaged in legal analysis of the application of effective legislation on legal entities,
including with respect to natural resources, including of oil and gas. He took part in
discussing the draft concept for development of corporate law in Russia and measures
to implement it. Mr Danilov has been directly involved in the drafting of new Russian
laws in the field of economics, international and foreign trade contracts and agreements.
As Head of the Research Advisory Council of the Constitutional Commission
and Deputy Head of the Federative and Interethnic Relations Department of the
Russian Parliament, he took an active part in drafting the Federative Treaty (1992) and
the Russian Constitution (1993) and was responsible for relevant legal matters arising
during that difficult period in Russia’s history. Mr Danilov was later appointed Head of
the State Duma Legal Department.
Mr Danilov has spoken and debated at many international conferences in Russia
and throughout the world.
Patrick Duffy
Stikeman Elliott LLP
Patrick Duffy is a lawyer in the energy and litigation sections in Toronto. Mr Duffy’s
practice is focused on energy regulation and environmental litigation. He is a member
of the Bars of Ontario and Alberta and has experience in proceedings before all levels of
court and a variety of administrative tribunals, including the Ontario Energy Board and
the Ontario Municipal Board. He represents both private and public sector clients on
matters related to energy regulation and advises clients on environmental assessments,
permitting, and Aboriginal consultation. Mr Duffy was the clerk for the Federal Court of
Canada, Trial Division, from 2002 to 2003. He also served as counsel for the Independent
Electricity System Operator (IESO) during a one-year secondment in 2007.
Ken Etim
Banwo & Ighodalo
Ken Etim is the managing partner and a partner in the energy practice at Banwo &
Ighodalo. He has almost 20 years’ experience of advising on, negotiating and closing
intricate and highly challenging multi-million-dollar transactions. He specialises
in Nigerian and international oil, gas and electricity work and is also experienced in
corporate, commercial and project finance transactions and has been involved in almost
all of the firms energy and project finance transactions. He regularly acts for a cross
section of companies and governments and is recognised in international guides as one
of the world’s leading energy lawyers. He is a member of the Nigerian Bar Association,
the Association of International Petroleum Negotiators (AIPN), Nigerian Maritime Law
Association and the Commercial Law & Taxation Committee of the Lagos Chamber of
Commerce & Industry, among other associations.
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Fabrice Fages
About the Authors
Latham & Watkins AARPI
Fabrice Fages is a litigator with a focus on litigation and arbitration. He has also developed
strong experience in regulatory and public policy, notably in regulated sectors such as the
energy sector. Prior to joining Latham & Watkins, Mr Fages has worked for the French
Senate and the French National Assembly on various law drafts. He is a regular speaker
at professional conferences related to energy. Mr Fages is also a lecturer at the University
of Paris I (Sorbonne University), École Centrale de Paris and the University of Cairo.
Michael J Gergen
Latham & Watkins LLP
Latham partner Michael Gergen has extensive experience developing practical
applications of economics, finance and regulatory law to assist clients in the electric,
natural gas and other network industries to compete successfully in an environment of
market-based, open-access competition. Mr Gergen is recognised as a leading energy
lawyer by Chambers USA and by The Best Lawyers in America.
Natasha Gianvecchio
Latham & Watkins LLP
Latham partner Natasha Gianvecchio focuses her practice on the regulatory and regional
energy market developments that impact clients in the electric and natural gas industries.
Her representations involve a broad range of issues under various federal and state
energy statutes and regulations and regional energy market rules affecting the domestic
energy industry. Ms Gianvecchio is consistently recognised as a leading energy lawyer by
Chambers USA.
Mitzi Gilligan
Minter Ellison
Mitzi Gilligan has been practising in commercial law and regulation since 1990. A
respected adviser to corporate clients, government and public sector agencies, she is
specifically recognised for her work in climate change and energy and resources.
She advises clients in a range of industries including electricity, oil and gas,
telecommunications, higher education, public transport and water. Her extensive
expertise encompasses utilities regulation; acquisitions and sales; due diligence;
procurement; and projects. She also drafts and negotiates industry contracts and advises
on regulatory dispute resolution processes.
Drawing on a sound understanding of the complex regulatory and legal
framework surrounding climate change, Ms Gilligan advises regarding greenhouse and
energy reporting, emissions trading, carbon capture and storage and renewable energy
initiatives.
Over the past five years she has been consistently named as a leading individual
in the area of energy and resources in guides including Chambers Asia Pacific 2011,
Chambers Global 2010 and 2009 and Australian Legal Business Guide 2009, 2008
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About the Authors
and 2007. She has also been recognised in the area of climate change by Best Lawyers
International: Australia 2010 and 2011.
A member of the Australian Mining and Petroleum Law Association and the
Resources, Environment and Energy Law Committee of the Australian Law Council,
Ms Gilligan regularly presents conference papers and lectures on legal issues in energy
and climate change.
Brad Grant
Stikeman Elliott LLP
Brad Grant is a partner in Stikeman Elliott’s commercial energy group in Calgary, whose
practice focuses on commercial arrangements, primarily in the petroleum and natural gas
and power sectors. Mr Grant’s clients include petroleum and natural gas producers and
midstream companies, energy trading companies, power generation and transmission
companies, chemical companies and infrastructure companies. He is also actively
involved in the firm’s emissions trading and climate change group.
Mr Grant advises clients on matters including private share and asset purchases and
sales, joint venture arrangements, supply contracts, service contracts, operating contracts,
transportation and storage contracts, trading contracts, engineering, procurement and
construction contracts and numerous other transactional matters. A significant portion
of his practice involves advising on derivatives and derivative-related matters. He is listed
and recognised by The Canadian Legal Lexpert Directory 2011 as a leading practitioner
in the area of derivatives. Mr Grant is a member of the Law Society of Alberta and the
Calgary and Canadian Bar Associations. He is also vice chair for Inn from the Cold in
Calgary.
Guenther Grassl
Schoenherr Attorneys at Law
Guenther Grassl is an associate in Schoenherr’s regulatory practice group. Prior to that he
worked for serveral years for the Austrian Chamber of Commerce as a policy adviser in
the field of environment and energy politics. During that period he was actively involved
in the further development of the environmental law of Austria and the European
Union. He also participated in several stakeholder forums for WKO. In his professional
work he puts a special focus on the legal provisions regarding the licensing of industrial
installations. Dr Grassl holds a master and a doctor of laws degree from the University of
Vienna (Dr iur 2011, Mag iur 2003). He wrote his dissertation on the implementation
of the ‘non-deterioration-clause’ in clean air and clean water provisions of the European
Union in Austrian law.
Shamilah Grimwood
White & Case LLP (South Africa)
Shamilah Grimwood is a partner at White & Case and a member of the firm’s energy,
infrastructure and project finance group and is a member of both the South African
and New York bar associations. She is recognised as a leading lawyer in the areas of
project and infrastructure finance in the power sector and public private partnerships.
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About the Authors
Her practice also extends to public-sector finance, administrative and regulatory practice
and telecommunications.
Ms Grimwood was a partner in the commercial law practice group of a leading
South African law firm before joining the New York office of White & Case in 1998 to
focus on project finance in the power sector. She has also advised both government and
the lenders on public private partnership arrangements.
Ms Grimwood has been recognized as a leading member of the team ranked
in the Legal 500 Europe, Middle East and Africa 2009 for South Africa: Projects and
Infrastructure, and South Africa: Project Finance/PPP as well as being highly ranked in
Chambers Global 2009 for South Africa: Project Finance/PPP and in 2009 for Africa:
Projects & Energy. She has also been recommended in PLC Which Lawyer rankings
2009 in the Energy Sector: South Africa and has been recognised as a leading lawyer in
the Euromoney Guide to the World’s Leading Energy and Natural Resources Lawyers (2007).
Martin Gynnerstedt
Mannheimer Swartling
Martin Gynnerstedt is a senior associate in Mannheimer Swartling’s corporate commercial
practice group and he is also the secretary of the firm’s energy industry group. Mr
Gynnerstedt specialises in energy law and contract law, and have has experience from
numerous international and Swedish transactions. He studied at the University of Lund
(LLM, 2000; MBA 2001). After service in the Swedish courts and work as a legal officer
at the Ministry of Industry, Mr Gynnerstedt joined Mannheimer Swartling in 2008.
Malin Håkansson
Mannheimer Swartling
Malin Håkansson is a senior associate in Mannheimer Swartling’s infrastructure and
corporate commercial practice group and a member of the firm’s energy industry group.
She specialises in construction law, energy law, contract law and public procurement
and has experience from numerous international and Swedish infrastructure and project
finance projects. Ms Håkansson studied at the Lund University (LLM, 1998). After
service in the Swedish courts, she joined Mannheimer Swartling in 2001.
Shun Hirota
Anderson Mōri & Tomotsune
Shun Hirota is an associate at Anderson Mōri & Tomotsune. He studied at the University
of Tokyo (LLB) and the University of Tokyo School of Law (JD) and is a member of the
Dai-ni Tokyo Bar Association.
Euripides Ioannou
PotamitisVekris Law Partnership
Euripides Ioannou specialises in the areas of banking and finance, project finance and
energy. His experience includes acting on a wide range of complex project finance,
concessions, structured finance and acquisition transactions. His energy practice includes
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About the Authors
advising clients on regulatory and environmental matters, thermal and renewable energy
projects, biofuels, geothermal energy and electricity trading.
Akshay Jaitly
Trilegal
Akshay Jaitly is a partner in the Delhi office of Trilegal. He heads the firm’s energy,
projects and infrastructure practice. He has considerable experience in advising on energy
and infrastructure projects, including in sectors such as power, oil and gas, water and
transport (roads and metro rail). He has advised some of the largest infrastructure entities
in the Indian market and also represents major international players with significant oil
and gas interests in India. Mr Jaitly has advised on tenders, regulation and all types of
project development, fuel supply and offtake contracts and particularly so in the oil,
natural gas and petroleum sector including LNG and, more recently, in coal and coal bed
methane related projects in various parts of India. He also advises on renewable energy
and CDM projects and has represented numerous projects including wind, hydro,
biomass and solar.
Jan Erik Janssen
Stek
Jan Erik Janssen is a competition and regulatory expert. He represents companies in
administrative and civil litigation and in front of competition authorities, regulators
and policy makers. He has been consistently recommended as one of the leading energy
and competition lawyers in the Netherlands. Mr Janssen is a founding editor of the
Netherlands Journal for Energy Law. In 2008 his peers voted him the best energy lawyer
in the Netherlands.
Rudi Kruse
Minter Ellison
Rudi Kruse joined Minter Ellison in February 2011 as a graduate after completing a
JD degree from the University of Melbourne and a combined bachelor of science and
bachelor of arts degree from the University of Sydney.
Mr Kruse has a keen interest in regulatory matters within the energy and resources
sector. He has previously advised both public and private sector clients on regulatory
matters and has published on the law and policy of Australia’s climate change regulations.
Nicholas Liau
Minter Ellison
Nicholas Liau graduated from the University of Melbourne with a bachelor of laws
(honours) and bachelor of science (honours). As a graduate, Mr Liau has assisted in
advising on regulatory-related matters, in particular within the electricity and gas sectors.
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Atsutoshi Maeda
About the Authors
Anderson Mōri & Tomotsune
Atsutoshi Maeda is a partner at Anderson Mōri & Tomotsune. He studied at the
University of Tokyo (LLB) and University College London (LLM) and is a member of
the Dai-ni Tokyo Bar Association.
Neeraj Menon
Trilegal
Neeraj Menon is a counsel in the energy, projects and Infrastructure team of Trilegal. His
primary areas of practice are energy and infrastructure projects and project financing. In
the energy sector, he has experience in advising conventional power generators on tariff
based competitive bid projects, power purchase agreements, fuel supply and transport
arrangements, EPC and O&M contracts and mine developer and operator contracts. He
has acted as lenders legal counsel in financing of various thermal and transmission power
projects. In the renewable energy sector, Mr Menon has extensive experience in advising
clients on all aspects of developing wind and solar power projects. He also advises clients
on regulatory issues concerning coal linkages and captive mining arrangements, land
acquisition and labour welfare legislations. He has also advised clients on development
of mass rapid transport systems, airport development projects and mega-residential
township projects.
Simone Monesi
Latham & Watkins LLP
Simone Monesi is a partner in the Milan office. His practice focuses primarily on mergers
and acquisitions (particularly in the real estate and energy sectors) and fund formation.
Prior to joining Latham & Watkins in 2008, Mr Monesi was a partner of Bonelli
Erede Pappalardo. He graduated magna cum laude from Milan State University.
ANTONIO MORALES
Latham & Watkins LLP
Antonio Morales is the responsible partner for the regulatory and litigation practice in
the Spanish offices of Latham & Watkins, as well as being part of the environmental,
land and resources practice group. Mr Morales’ practice focuses on projects and
transactions relating to public and administrative law, including the energy, utility, water
and telecommunications sectors.
In 1997, Mr. Morales became a state attorney. During his time in the public
administration, he worked at the government delegation in Madrid from 1998 to 1999
and from 1999 to 2002 at the Tribunal Superior de Justicia of Madrid. From 2002 and
2005 he served as Secretary General of the Spanish Nuclear Safety Council. Prior to
joining Latham & Watkins, Mr Morales was a partner at Lovells. In 2008, Mr Morales
obtained his PhD at the Universidad Autonoma de Barcelona. He currently sits on the
Legal Commission of the Spanish Olympic Committee.
Mr Morales has been recognised as a leader in administrative and public law by
Chambers Global for the past four years and in the energy sector by Chambers Europe
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About the Authors
from 2008 to 2010. Additionally, he has been recognised as a leading Iberian energy
lawyer by Iberian Lawyer in June 2006. In 2007 Mr Morales also received a ‘40 under
forty’ award presented by Iberian Lawyer.
Sitesh Mukherjee
Trilegal
Sitesh Mukherjee is a partner in the Delhi office of Trilegal. His principal areas of practice
are dispute resolution and energy regulation. He is a member of the Supreme Court Bar
Association, Delhi High Court Bar Association and the American Bar Association. Mr
Mukherjee is experienced in arbitration and economic regulatory matters (specifically
electricity, airports, oils and gas, telecommunications and competition law) in the
Supreme Court of India, various high courts and tribunals.
Darshini Nanthakumar
Minter Ellison
Darshini Nanthakumar advises on commercial and regulatory matters with a particular
focus on the energy and resources sector. Her experience in the government sector
includes advising on a range of matters for both Victorian departments and agencies.
Ms Nanthakumar recently completed a lengthy secondment as in-house counsel
to a state-based government department responsible for energy regulation in Victoria.
Zahra Omar
White & Case LLP (South Africa)
Zahra Omar is an Alberta (Canada) qualified lawyer. She is a senior associate at White &
Case in the firm’s Johannesburg office and a member of the firm’s energy infrastructure,
project and asset finance group. Prior to joining White & Case, Ms Omar was an
associate at a leading Canadian firm. Since joining White & Case, she has advised both
government and the lenders on public-private partnership arrangements. Her particular
interest in environmental issues, including climate change in South Africa, causes
her to seek out opportunities to assist companies in understanding their national and
international obligations in this arena.
Ayodele Oni
Banwo & Ighodalo
Ayodele Oni, a Shell Scholar and winner of the young lawyer of the year award in the
maiden edition of the Nigerian Legal Awards, is a senior associate in the energy and
natural resources team of Banwo & Ighodalo. He has a broad range of experience in
energy (oil, gas and power), corporate and commercial matters with particular focus on
energy. Mr Oni has acted for a broad range of clients in the energy sector assisting on
various energy transactions. He also writes a column on energy in a Nigerian business
newspaper.
366

Christian Poulsson
About the Authors
Kvale Advokatfirma DA
Christian Poulsson is a partner at Kvale in Oslo. He has been engaged in the electricity
sector since 1996, first as in-house counsel at Norsk Hydro ASA, then after 15 months
as a judge, for the past 12 years as an attorney in Oslo-based law firms. He has written
several articles in various publications.
Pudji W Purbo
Makarim & Taira S
Pudji Purbo is a partner at Makarim & Taira S. She studied at the University of Indonesia
in Jakarta, and received her LLM from the Fordham School of Law, at Fordham
University in New York (1999).
Areas of expertise include energy, natural resources (oil and gas, mining, geothermal),
project finance, mergers and acquisitions, and corporate and commercial law.
Ms Purbo represents multinational companies in natural resources and energy
and has been involved in a wide variety of transactions in the mining, oil and gas and
power industries. She has extensive experience dealing with government agencies and
state-owned enterprises, including Pertamina, the state-owned oil and gas company, and
PT PLN, the state electricity company. Ms Purbo has handled, inter alia, acquisitions of
gas assets, oil and gas and mining concessions, gas sales financing and electricity projects.
Dimitra Rachouti
PotamitisVekris Law Partnership
Dimitra Rachouti’s practice includes advising on all aspects energy and environmental
law. She has participated in a number of due diligence reviews, in particular in the area
of energy and project finance.
Georges P Racine
Lalive and Lalive in Qatar LLC
Georges Racine is a partner of Lalive and a director of Lalive in Qatar LLC. He is a dualqualified
civil and common law lawyer with intimate knowledge of developing countries
and emerging markets. He has wide-ranging experience in corporate, commercial and
international business law, with particular emphasis on projects (energy, infrastructure,
telecoms and transport), construction, licensing and concessions, privatisations, mergers
and acquisitions, joint ventures, public–private partnerships (PPPs), foreign investment
and public procurement. Mr Racine has acted as lead counsel in international projects
and transactions in over 25 countries worldwide. He was a member of the expert group
that advised the Secretariat of the United Nations Commission on International Trade
Law (UNCITRAL) on its draft Legislative Guide on Privately Financed Infrastructure
Projects. He has written several articles on energy, infrastructure, telecommunications,
PPPs and other subjects for international publications and attended several international
conferences as a speaker. He has also acted for several international investment banks,
international financial institutions (e.g., World Bank, IFC, EBRD), foreign governments,
regulatory authorities, sponsors, developers, independent power producers, utilities,
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About the Authors
trading firms, contractors, service providers, suppliers, investors, and consulting,
engineering and accounting firms.
Bernd Rajal
Schoenherr Attorneys at Law
Bernd Rajal is partner with Schoenherr in Vienna, where he is a member of the firm’s
regulatory practice group. He is also a member of the Steering Committee of Schoenherr’s
energy group. Mr Rajal’s practice focuses on regulatory issues such as energy, environment,
waste and water management, emission trading and restoration of contaminated sites.
He advises energy suppliers with regard to EIA approvals and realisation of hydro-power
plants. He advises the Association of Austrian Electricity Companies with regard to
the implementation of the EU Third Energy Package. With Schoenherr representing
various governmental departments, he is also involved in legislative procedures making
proposals for the amendment of energy and environmental law provisions. Moreover,
he advises foreign governmental departments (such as OPCOM in Romania) on the
implementation of black, green and white certificate schemes into national law. Mr Rajal
is heavily involved in wind park projects and coordinates due diligence proceedings
related to transactions in the energy and environmental sectors.
Erik Richer La Flèche
Stikeman Elliott LLP
Erik Richer La Flèche is a partner in the Montréal office of Stikeman Elliott specialising
in commercial transactions in Canada and abroad, including capital and natural resource
projects, PPPs and project finance. He has led large projects in more than 25 countries.
From 1981 to 1984 he was seconded to Anderson Mōri Tomostune (Tokyo). He is
currently involved in an aluminum smelter expansion (Canada), wind farms (Canada),
hospitals (Canada), a railroad (Asia Minor), central heating and cooling systems
(Canada), and a high-voltage transmission line (Canada–USA). Included in Euromoney’s
Guide to the World’s Leading Project Finance Lawyers, The International Who’s Who of Public
Procurement Lawyers, Who’s Who Legal Canada, Chambers Global’s The World’s Leading
Lawyers for Business and IFLR1000: Guide to the World’s Leading Financial Law Firms.
Regularly advises governments and lectures on foreign investments, natural resources
and infrastructure. He is a member of both the Québec (1979) and Ontario Bars (1986).
Myria Saarinen
Latham & Watkins AARPI
Myria Saarinen is a partner in the litigation department of the Paris office of Latham &
Watkins. Ms Saarinen’s practice focuses on resolving a broad range of complex disputes
through litigation proceedings, mostly in an international context, and in various areas
of business, including in the energy sector.
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About the Authors
Guilherme Guerra D’Arriaga Schmidt
L O Baptista Schmidt Valois Miranda Ferreira Agel
Guilherme Guerra D’Arriaga Schmidt has an extensive practice in energy, infrastructure,
arbitration, M&A, tax and corporate transactions. From 1990 to 1993, he worked for
Shell in Brazil as a tax lawyer. He joined Veirano Advogados in 1993 and worked until
2000, first as a lawyer and then as a partner acting in commercial contracts, infrastructure
and regulatory law.
He was a former visiting associate at O’Melveny & Myers LLP, New York, from
1998 to 1999. For six years he was a partner of Machado, Meyer, Sendacz e Opice
Advogados, responsible for matters involving commercial contracts, infrastructure,
regulatory law and arbitration. He was nominated as a leading lawyer in energy and
natural resources by Chambers and Partners in the 2007, 2008, 2009, 2010 and 2011
editions, in corporate/M&A in the 2008, 2009, 2010 and 2011 editions, and projects
in the 2008, 2009 and 2011 editions. He was listed as one of the ‘leading lawyers’ in the
area of energy and natural resources by the Expert Guides in 2007, 2009 and 2010. He
was also listed in The International Who’s Who of Business Lawyers in 2010 and 2011, in
the oil and gas sector. Further to this, he was nominated as a ‘most admired lawyer’ by
Análise Advocacia 2010, in infrastructure.
Mr Schmidt graduated from the Universidade do Estado do Rio de Janeiro
(UERJ) in 1989 and has a postgraduate degree in tax law from the Universidade Candido
Mendes (UCAM), under the coordination of the Brazilian Financial Law Association
(ABDF). He is an arbitrator at the Câmara de Arbitragem Empresarial, in the state of
Minas Gerais in Brazil.
David L Schwartz
Latham & Watkins LLP
David Schwartz is a partner in the finance department of Latham & Watkins’ Washington,
DC office. He serves as global chair of the energy regulatory and markets practice, is a
member of the project finance group, and is co-chair of the firm’s global energy – power
industry group. He has extensive experience representing entities involved in electric
generation, transmission and distribution, electric and gas marketing and trading, and
gas transportation and distribution.
Mr Schwartz has been active in the formation of the developing electricity markets
in the United States; led transactional and regulatory teams in mergers and acquisitions
and divestitures of energy companies and assets; litigated contract, rate and transmission
access disputes; and drafted federal and state energy legislation. He also has extensive
experience in negotiating power purchase and sale agreements, electric transmission
agreements, natural gas transportation agreements, energy management agreements, and
electric and gas interconnection agreements.
Mr Schwartz regularly advises clients on energy matters before the Federal Energy
Regulatory Commission (FERC), various state public utility commissions, the US
Department of Justice (DoJ), the Federal Trade Commission (FTC), the Securities and
Exchange Commission (SEC), the Commodity Futures Trading Commission (CFTC)
and the Department of Energy (DoE).
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About the Authors
Mr Schwartz is regularly named as a leading energy lawyer in Corporate Counsel
Magazine, Best Lawyers in America, The Legal 500 US and both the global and the US
Chambers & Partners Guides to Leading Business Lawyers. Mr Schwartz is a member
of the American Bar Association and has held leadership positions in the Energy Bar
Association.
Vibhu Sharma
Trilegal
Vibhu Sharma is an associate in the Delhi office of Trilegal. Her principal areas of practice
are dispute resolution and energy regulation. She has represented major international
and Indian players in economic regulatory matters (specifically electricity, airports and
competition law) in the Supreme Court of India, various high courts and tribunals.
Yassen Spassov
Djingov, Gouginski, Kyutchukov & Velichkov, attorneys and counsellors at law
Yassen Spassov is an associate at Djingov, Gouginski, Kyutchukov & Velichkov with
more than three years’ legal experience, now primarily working in the fields of energy
and environmental law. He is a qualified lawyer in Bulgaria, who acquired his qualifying
law degree from the Sofia University St Kliment Ohridski. Later, he graduated an LLM
course in environmental law and policy at University College London.
Mr Spassov’s experience has mostly been concentrated in the energy and utilities
practice of Djingov, Gouginski, Kyutchukov & Velichkov with a particular focus on
acquisitions and financing of renewable energy plants, actions against grid operators
and appeal proceedings before the energy regulator (SEWRC). The practice group
also engages in emissions trading, waste management and other regulatory aspects of
environmental protection.
Yuko Suzuki
Anderson Mōri & Tomotsune
Yuko Suzuki is an associate at Anderson Mōri & Tomotsune. She studied at the University
of Tokyo (LLB) and the University of Tokyo School of Law (JD) and is a member of the
Dai-ni Tokyo Bar Association.
Reiji Takahashi
Anderson Mōri & Tomotsune
Reiji Takahashi is a partner at Anderson Mōri & Tomotsune. He studied at the University
of Tokyo (LLB) and the University of Virginia (LLM). He is a lecturer of University of
Tokyo Graduate Schools of Law and Politics and is admitted to the Bar in Japan (Dai-ni
Tokyo Bar Association) and New York.
Arnoldo Troconis
D’Empaire Reyna Abogados
Arnoldo Troconis obtained his law degree cum laude from the Universidad Católica
Andrés Bello in Caracas, (1988) and an MCJ from the University of Texas, Austin,
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About the Authors
Texas, (1991). He holds a master’s degree in tax from the Universidad Católica Andrés
Bello (1994) and was a professor of contract law at Universidad Católica Andrés Bello
(from 2005 to 2006). Mr Troconis interned at Graves, Dougherty, Hearon and Moody
in Austin, (1991) and has also been a professor of internationalisation and law at the
Instituto de Estudios Superiores de Administración (IESA). He is a member of the
Association of International Petroleum Negotiators (AIPN). Mr Troconis is fluent in
Spanish, English and Italian.
Zeynel Tunç
Paksoy Attorneys at Law
Zeynel Tunç is a senior sssociate at Paksoy in Istanbul, and specialises in project finance,
energy law, contract law and mergers and acquisitions. He has considerable experience in
construction, engineering and landmark infrastructure projects, drafting and negotiating
turnkey EPC contracts, off-take agreements, conducting due diligence, particularly on
energy projects, as well as in conducting governmental licensing and environmental
compliance checks. Mr Tunç is experienced in drafting and negotiating short and longterm
loan and project finance agreements.
Mr Tunç worked at Paksoy between 2005 and 2007, and subsequently worked
for EnerjiSA Group as head of legal from 2007 until he rejoined Paksoy in 2012. He
substantially extended his experience to include energy generation and trade, electricity
distribution and gas supply-related matters.
A graduate of Kocaeli University Law School, Mr Tunç also holds an LLM
degree in international commercial law from the University of Westminster and holds
an executive MBA degree from Sabanci University. He is admitted to the Istanbul Bar.
Dirk Uwer
Hengeler Mueller
Dirk Uwer graduated from Trier law school and subsequently obtained master’s degrees
in public administration from the German University of Administrative Sciences and
in European law from Northumbria University. He was a lecturer at the Institute for
Environmental and Technology Law of Trier University from 1994 to 1997. In 1998
he was conferred a doctorate in law from Humboldt-University Berlin. Dr Uwer has
published numerous articles on various topics of both European and German public law,
with a particular focus on energy and environmental law.
Dr Uwer regularly advises on energy and other regulatory matters. A large
proportion of his time is devoted to transactional and restructuring work, including the
unbundling of vertically integrated utilities. Chambers Europe 2012 ranks him among
the leading German lawyers in the energy sector. His broad energy practice includes grid
access and grid tariff regulation, infrastructure projects such as pipelines, power stations
and gas storage and has a particular focus on renewable energy projects and prioritisation.
Dr Uwer’s recent transactional work includes RWE’s sale of gas TSO Thyssengas,
RWE’s sale of a majority stake in electricity TSO Amprion, TenneT’s acquisition of
E.ON’s electricity TSO transpower, and E.ON’s sale of gas TSO Open Grid Europe.
371

Gonzalo A Vargas
About the Authors
González Calvillo, SC
Gonzalo Vargas is a transactional attorney with over 26 years of experience providing
legal and business advice and counselling to multinational and Mexican companies.
He co-heads González Calvillo’s energy and real estate and hospitality practice groups.
His work includes active representation of diverse clients involved in a wide variety
of projects, including multi-million-dollar transactions and investments in the areas
of joint ventures, oil service industry, government procurement, real estate and ADR.
Recognised as a business-oriented practitioner, Mr Vargas is an active member on the
boards of directors of several joint-venture companies.
His practice also focuses on M&A, sophisticated corporate structures as well as
issues and disputes between shareholders, hospitality industry, energy industry, crossborder
investments, complex agreements, corporate finance, antitrust regulation, private
equity/venture capital transactions, public bids and regulatory issues in general, as well
as arbitration. Mr Vargas has been consistently ranked as a foremost practitioner in his
fields of expertise by Chambers & Partners, Who’s Who and Latin Lawyer.
Carolyn Vigar
Minter Ellison
Carolyn Vigar specialises in commercial public law issues and regulatory design for
major public and government sector projects and clients. She has extensive experience
in regulatory and legislative reform, administrative law, constitutional and commercial
issues, responsible government, public sector accountability, and the Charter of Human
Rights and Responsibilities.
Ms Vigar has particular skill in energy sector regulation, market reforms and
commercial transactions including relating to renewable and co‐generation, tri‐generation
and carbon geosequestration projects.
An expert in regulatory design, she has helped develop and structure regimes
across the energy, water, transport infrastructure, primary industries and professional
sectors. She also advises on the streamlining and reform of regulation to facilitate major
infrastructure projects.
Carolyn has been closely involved in implementing major government policy
initiatives such as national energy market reforms, the national competition policy,
national social housing reforms, reform of the vocational education and training sector,
electricity privatisation and public transport reforms.
Genevieve Watt
Minter Ellison
After graduating from Monash University with a combined bachelor of laws and bachelor
of arts degree, Genevieve Watt joined Minter Ellison in March 2011 as a graduate.
During her time at Minter Ellison, she has advised both public and private sector clients
on a range of general commercial, regulatory and technology matters.
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About the Authors
Glenn Zacher
Stikeman Elliott LLP
Glenn Zacher is a partner in the litigation and energy section in Toronto. His practice
focuses on commercial litigation and energy regulatory law. He was called to the Bars
of Ontario and British Columbia and has appeared before all levels of court in both
provinces. Mr Zacher has also conducted arbitrations and has acted as counsel before
various administrative tribunals, including the Ontario Energy Board (OEB), the British
Columbia Utilities Commission (BCUC) and the Ontario Securities Commission (OSC).
Mr Zacher’s energy regulatory practice includes advising and representing public
agencies and private sector companies (generators, marketers, transmitters) before
the Ontario Energy Board and in review and appeal proceedings before the Ontario
Divisional Court and the Ontario Court of Appeal. He also acts for energy clients in
complex commercial litigation disputes. In 2002, Mr Zacher spent a year’s secondment
at the Independent Electricity System Operator (IESO) where he acted as counsel to the
IESO during the lead-up to and for the first eight months following the opening of the
restructured Ontario electricity market.
Mr Zacher has been recognised in The 2012 Chambers Global’s The World’s Leading
Lawyers for Business as a recommended lawyer in Energy: Power (Regulatory) and in
LawDay – Leading Lawyers: Energy – Regulatory 2009.
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Appendix 2
Contributing Law Firms’
contact details
Afridi & Angell
Emirates Towers – Level 35
Sheikh Zayed Road
Dubai
United Arab Emirates
Tel: +971 4 330 3900
Fax: +971 4 330 3800
mafridi@afridi-angell.com
hbaryalay@afridi-angell.com
www.afridi-angell.com
Anderson Mōri
& Tomotsune
Izumi Garden Tower
6-1, Roppongi 1-chome, Minato-ku
Tokyo 106-6036
Japan
Tel: +81 3 6888 1000
reiji.takahashi@amt-law.com
atsutoshi.maeda@amt-law.com
shun.hirota@amt-law.com
yuko.suzuki@amt-law.com
www.amt-law.com/en/
Banwo & Ighodalo
98 Awolowo Road
South West Ikoyi
Lagos
Nigeria
Tel: +234 1 4615203-4
Fax: +234 1 4615205
ketim@banwo-ighodalo.com
aoni@banwo-ighodalo.com
www.banwo-ighodalo.com
D’Empaire Reyna Abogados
Plaza La Castellana, Edif. Bancaracas
PH Caracas
Venezuela
Tel: +58 21 2264 6244
Fax: +58 21 2264 7543
atroconis@dra.com.ve
www.dra.com.ve
374

Contact Details
Djingov, Gouginski,
Kyutchukov & Velichkov,
attorneys and counsellors
at law
10 Tsar Osvoboditel blvd
Sofia 1000
Bulgaria
Tel: +359 2 932 11 00
Fax: +359 2 980 35 86
yassen.spassov@dgkv.com
www.dgkv.com
Goltsblat BLP
Capital City Complex
Moscow City Business Centre 8
Presnenskaya Nab, Bldg 1
Moscow 123100
Russia
Tel: +7 495 287 4444
Fax: +7 495 287 4445
info@gblplaw.com
www.gblplaw.com
Gómez-Pinzón Zuleta
Calle 67 No. 7-35
Of. 1204 Edificio Caracol
Bogotá
Colombia
Tel: +571 319 29 00
Fax: +571 321 02 95
parrazola@gpzlegal.com
fardila@gpzlegal.com
www.gpzlegal.com
GonzÁlez Calvillo, SC
Montes Urales No. 632, Piso 3
Lomas de Chapultepec
CP 11000 Mexico City
Mexico
Tel: +52 55 5202 7622
Fax: +52 55 5220 7671
gvargas@gcsc.com.mx
www.gcsc.com.mx
Hengeler Mueller
Benrather Str 18-20
40213 Düsseldorf
Germany
Tel: + 49 211 8304 132
Fax: + 49 211 8304 170
dirk.uwer@hengeler.com
www.hengeler.com
Hogan Lovells
Atlantic House
Holborn Viaduct
London EC1A 2FG
United Kingdom
Tel: +44 20 7296 2000
Fax: +44 20 7296 2001
elisabeth.blunsdon@hoganlovells.com
www.hoganlovells.com
Kvale Advokatfirma DA
PO Box 1752 Vika
0122 Oslo
Norway
Tel: +47 22 47 97 00
Fax: +47 21 05 85 85
post@kvale.no
pca@kvale.no
www.kvale.no
L O Baptista Schmidt Valois
Miranda Ferreira Agel
Rua da Assembléia 66 – 17° andar
Centro
20011-000
Rio de Janeiro RJ
Brazil
Tel: +55 21 2114 1700
Fax: +55 21 2114 1717
gschmidt@lob-svmfa.com.br
www.lob-svmfa.com.br
375

Contact Details
LALIVE
35 Rue de la Mairie
PO Box 6569
1211 Geneva 6
Switzerland
Tel: +41 22 319 8759
Fax: +41 22 319 8760
gracine@lalive.ch
2 Löwenstrasse
PO Box 2779
8021 Zurich
Switzerland
Tel: +41 44 319 80 00
Fax: +41 44 319 80 19
www.lalive.ch
LALIVE IN QATAR LLC
QFC Tower 1, 8th Floor
PO Box 23495
West Bay, Doha
Qatar
Tel: +974 4496 7247
Fax: +974 4496 7244
gracine@lalive.ch
www.laliveinqatar.com
Latham & Watkins AARPI
53 quai d’Orsay
Paris 75007
France
Tel: +33 1 4062 2000
Fax: +33 1 4062 2062
fabrice.fages@lw.com
myria.saarinen@lw.com
www.lw.com
Latham & Watkins LLP
Corso Matteotti 22
20121 Milan
Italy
Tel: +39 02 3046 2000
Fax: +39 02 3046 2001
simone.monesi@lw.com
Maria de Molina 6, 4th floor
Madrid 28006
Spain
Tel: +34 91 971 5000
Fax: +34 902 882 228
antonio.morales@lw.com
555 11th Street, NW
Suite 1000
Washington, DC 20004
United States
Tel: +1 202 637 2200
Fax: +1 202 637 2201
michael.gergen@lw.com
natasha.gianvecchio@lw.com
david.schwartz@lw.com
www.lw.com
Makarim & Taira S
Summitmas Tower I, 16-17th Floors
Jalan Jendral Sudirman Kav. 61-62
Jakarta 12190
Indonesia
Tel: +62 21 252 1272
Fax: +62 21 252 2750
pudji.purbo@makarim.com
www.makarim.com
376

Contact Details
Mannheimer Swartling
PO Box 1711
111 87 Stockholm
Sweden
Tel: +46 8 595 06000
Fax: +46 8 595 06001
han@msa.se
mgy@msa.se
hak@msa.se
www.mannheimerswartling.se
Minter Ellison
Rialto Towers, 525 Collins Street
Melbourne
3000 VIC
Australia
Tel: +61 3 8608 2000
Fax: +61 3 8608 1000
mitzi.gilligan@minterellison.com
www.minterellison.com
Paksoy Attorneys at Law
Sun Plaza
Bilim Sok No. 5 K:14
Maslak 34398
Istanbul
Turkey
Tel: +90 212 366 4700
Fax: +90 212 290 2355
ztunc@paksoy.av.tr
www.paksoy.av.tr
PotamitisVekris Law
Partnership
Neofytou Vamva 9
10674 Athens
Greece
Tel: +30 21 0338 0000
Fax: +30 21 0338 0020
euripides.ioannou@potamitisvekris.com
dimitra.rachouti@potamtisvekris.com
www.potamitisvekris.com
Schoenherr Attorneys at
Law
Tuchlauben 17
1010 Vienna
Austria
Tel: +43 1 534 37 0
Fax: +43 1 534 37 6100
b.rajal@schoenherr.eu
g.grassl@schoenherr.eu
www.schoenherr.eu
Stek
Herengracht 551
1017 BW Amsterdam
Netherlands
Tel: +31 20 530 52 00
Fax: +31 20 530 52 99
janerik.janssen@steklaw.com
martha.brinkman@steklaw.com
www.steklaw.com
Stikeman Elliott LLP
5300 Commerce Court West
199 Bay Street, Toronto
Ontario M5L 1B9
Canada
Tel: +1 416 869 5500/5688
Fax: +1 416 947 0866
gzacher@stikeman.com
ericherlafleche@stikeman.com
bgrant@stikeman.com
pduffy@stikeman.com
www.stikeman.com
377

Contact Details
Trilegal
A38 Kailash Colony
New Delhi 110048
India
Tel: +91 11 4163 9393
Fax: +91 11 4163 9292
One Indiabulls Centre
14th Floor, Tower One
Elphinston Road
Mumbai 400 013
India
Tel: +91 22 4079 1000
Fax: +91 22 4079 1098
The Residency, 7th Floor
133/1, Residency Road
Bangalore 560 025
India
Tel: +91 80 4343 4646
Fax: +91 80 4343 4699
Harmony Plaza
2nd Floor, 3-6-387/C
Main Road, Himayat Nagar
Hyderabad 500029
India
Tel: +91 40 6641 5056
Fax: +91 40 6641 5057
akshay.jaitly@trilegal.com
sitesh.mukherjee@trilegal.com
neeraj.menon@trilegal.com
vibhu.sharma@trilegal.com
www.trilegal.com
White & Case LLP (South
Africa)
The Reserve
54 Melville Road
Illovo, Johannesburg 2196
South Africa
Tel: +27 11 341 4000
Fax: +27 11 327 1900
sgrimwood@whitecase.com
zomar@whitecase.com
www.whitecase.com
Zul Rafique & Partners
D3-3-8 Solaris Dutamas
No 1, Jalan Dutamas 1
50480 Kuala Lumpur
Malaysia
Tel: +603 6209 8228
Fax: +603 6209 8221
lukman@zulrafique.com.my
www.zulrafique.com.my
378