Hunton & Williams Renewable Energy Quarterly, September 2009

Renewable Energy Quarterly 

September 2009 

In This Issue... 

Federal Climate 

Legislation: The End 

Would Be Just The 

Beginning....................... 1 

SPECIAL FEATURE: 

ASIAN MARKET 

Progress To Date in 

Implementing China’s 

Renewable Energy 

Law of 2006................ 4 


Development 

Prospects of 

Southeast Asia’s 

‘Green Tigers’............. 9 

Recovery Act Guidance 

Update........................... 17 

Ambiguities in ‘Buy 

American’ Rule Hamper 


Projects......................... 22 

Green Investment 

Funds: Threshold 

Considerations and 

Challenges.................... 26 

Industry Happenings... 30 

Federal Climate Legislation: The End Would Be Just 

The Beginning 

The U.S. Congress is now the center of climate change policy in the United States, but the passage 

of legislation for President Obama’s signature would not mark the end of the debate. The American 

Clean Energy and Security Act of 2009, as passed by the House on June 26, establishes only a 

broad framework for the reduction of greenhouse gas emissions. Essential details are delegated 

to the Environmental Protection Agency, the Department of Energy, the Department of Agriculture, 

the Federal Energy Regulatory Commission and the Commodities Futures Trading Commission for 

rulemaking. 

As a result, long after the ink from the president’s signature is dry, the EPA and other agencies will 

be busy crafting critical components of the bill’s programs that will determine — perhaps to a far 

greater extent than the legislation itself — both the obligations imposed on industry and the outcome 

for the environment. In other words, it will be up to the regulator in many instances to decide 

who wins and who loses. 

As it now stands, the bill contemplates no fewer than 22 agency rulemakings or major actions 

within the first year following enactment. An additional 20 rulemakings or actions are required within 

two years, and at least another 30 by 2020. 

If history is any guide, few of these rulemakings will be completed on time. For example, many of 

the rulemakings arising out of the Clean Air Act Amendments of 1990 took most of the 1990s to 

complete, and some key issues remain unresolved to this day. 

With the first compliance deadline for emitters of greenhouse gases slated for April 1, 2013, questions 

loom as to whether the EPA and other agencies will be able to finalize critical regulations far 

enough in advance for the U.S. carbon market to get off the ground. At best, it appears that a skeleton 

version of a cap-and-trade system could commence operation on time, but without key features 

designed to reduce compliance costs and provide regulatory certainty. At worst, regulatory gridlock 

could ensue, deterring investments in clean technology and disrupting efforts to reduce emissions. 

As an example, the bill provides for the distribution of “compensatory allowances” to covered entities 

that engage in certain types of “non-emissive” uses of greenhouse gases. The objective is to 

compensate businesses that, under the bill, would be forced to hold emission allowances for activities 

that do not result in emissions, such as the use of petroleum-based fuel as a feedstock. The bill 

calls for regulations providing for the creation and distribution of compensatory allowances within 

two years following enactment. But as noted above, this is just one of more than 40 rulemakings or 

major agency actions required in that time period. 

Covered entities eligible for compensatory allowances could face dramatically different compliance 

costs if such allowances were not available. This not only creates uncertainty, but it skews 

Hunton In The News.... 32 

Sahara Sun to Power Europe?............................................................................................. 30 

U.S. Military and Investors Help Algae Research Grow......................................................31


compliance costs and foils the kind of long-term planning 

and investment conducive to the development of new, 

climate-friendly technologies, products and processes. 

The situation is similar with respect to the offsets program 

established by the bill, but with far greater implications, 

as offsets arguably represent the only substantial cost 

containment mechanism in the entire bill. Despite providing 

a substantial amount of detail, the bill leaves some critical 

components of the offsets program to the EPA and the 

Department of Agriculture. For example, the bill does not 

provide a list of eligible offset project types, instead requiring 

the EPA and USDA to develop lists within one year of 

enactment. 

Once those are developed, the EPA and USDA would then 

need to develop and finalize project methodologies — complex, 

technical procedural requirements for an emission 

reduction project to be eligible to receive offset credits. The 

need to complete this process in two years raises concerns 

over when offset projects could begin generating offset credits, 

especially given that developing new offset projects could 

take years once the rules are finalized. 

Under the bill, the EPA and USDA 

would be expected to issue two billion 

offset credits each year. 

This tight timeframe becomes of even greater concern 

given the number of offset credits the EPA and USDA would 

need to issue each year to maximize the bill’s cost containment 

features. Existing offset programs such as the Clean 

Development Mechanism and various voluntary carbon market 

programs have never come close to issuing two billion 

credits over their entire multiyear lifetimes. Under the bill, the 

EPA and USDA would be expected to issue two billion offset 

credits each year. How many of those two billion would be 

available before the first compliance deadline in 2013 is an 

unanswered question. 

Compensatory allowances and the offsets program are 

just two examples of key features that will depend heavily 

on agency rulemaking processes that historically have 

been anything but expeditious. Legal challenges to agency 

rulemaking, which figured prominently in the rulemakings 

following the Clean Air Act Amendments of 1990, could add 

further delay to the full implementation of many of the bill’s 

most important provisions. 

Equally, if not more, significant than the timing of agency 

rulemakings is the extraordinary discretion the bill grants to 

the EPA and other agencies to alter components of the capand-trade 

system. 

Under the offsets provisions, for example, the EPA and 

USDA are required to revise key features of the program 

every five years as part of a periodic review. This authority 

is purportedly to ensure the environmental integrity and efficient 

operation of the cap-and-trade system. While these are 

important goals, the unchecked nature of this authority could 

frustrate project developers and covered entities seeking to 

participate in the carbon market. Most emission reduction 

projects take a year or more to develop and then can operate 

for a decade or longer. 

2 Renewable Energy Quarterly www.hunton.com


The risk that projects could lose their eligibility to generate 

offset credits, potentially with little notice, as a result of an 

EPA or USDA review could discourage investment in projects 

and hinder the emergence of a robust offset credit market. 

More broadly, even features of the cap-and-trade system 

seemingly carved in stone are subject to change. No more 

obvious example exists than the number of emission allowances 

the bill requires the EPA to establish for each year 

of the program. The precise numbers are listed in a table 

embedded in the text of the bill, but the EPA is authorized to 

change these numbers if, among other things, it determines 

that the underlying emissions data on which these numbers 

are based is inaccurate. 

The EPA may make such a change only once, but even a 

one-time change would affect the number of allowances allocated 

to covered entities, states, federal agencies and other 

groups. This in turn fosters uncertainty, raises compliance 

costs and could potentially destabilize the carbon market. 

There also are instances in which the bill delegates authority 

for key changes to entities outside the Executive Branch. For 

example, the bill requires the EPA to report to Congress on 

U.S. and foreign efforts to reduce emissions and to recommend 

additional actions to address climate change. The bill 

then requires the National Academy of Sciences — a private 

entity whose members are not appointed by the president 

— to review the report and issue its own recommendations. 

The president is then required to order agencies to use all 

existing authority to implement these recommendations and 

submit a report to Congress requesting additional legislative 

action where needed. 

Although these provisions do grant the National Academy 

and the president a limited amount of discretion, they 

nevertheless raise potential constitutional issues, as they 

effectively allow an entity that is untethered to the democratic 

process to tie the president’s hands and force potentially 

unpalatable action. 

In the end, what all this means is that as a comprehensive 

climate change regulatory regime inches closer to reality, 

its enactment will mark only the beginning of the jockeying 

between possible winners and losers in the new U.S. carbon 

markets. 



SPECIAL FEATURE: ASIAN MARKET 

Progress To Date in Implementing China’s Renewable Energy 

Law of 2006 

It has been three years since the People’s Republic of 

China (“PRC”) passed its Renewable Energy Law. In that 

time the PRC has enacted several key pieces of follow-on 

legislation and policy that fit together to form a comprehensive 

renewable energy program, although some issues 

remain unaddressed. This article aims to provide a general 

review of relevant law and policy, with a view to highlighting 

points likely to be of interest to a renewable energy project 

developer. 

China Energy Sector Background 

China relies heavily on coal to meet its power generation 

needs. China’s installed generating capacity as of 2005 

was roughly 519 gigawatts (GW). 1 At that time, China’s 

energy generation mix was as follows: 73.41 percent coal, 

15.22 percent large hydropower, 7.32 percent small hydropower, 

1.93 percent gas, 1.35 percent nuclear, 0.19 percent 

wind and 0.39 percent other sources. 2 

China’s electricity sector has undergone significant reform 

in the last decade. Until 2002, China’s power industry 

(including both generation and transmission capacities) 

was monopolized by the State Power Corporation (“SPC”), 

which owned 46 percent of China’s generation assets and 90 

percent of its distribution assets. The State Council, as part 

of power restructuring policy, dismantled SPC to facilitate the 

separation of plant and grid asset ownership. Eleven smaller 

companies were formed, namely: 

ÆÆ two grid operators: State Grid Corporation 

headquartered in Beijing and China Southern Power 

Grid Company Limited headquartered in Guangzhou; 

ÆÆ five power generation companies: China Power 

Investment Corporation, China Datang Corporation, 

1 

Experts estimate that China’s total installed generating capacity 

will pass the 900 GW mark in 2009; however, reliable data more 

recent than these figures from 2005 breaking down China’s energy 

mix was not available at the time this article was published. 

2 

McKinsey & Company. “China’s Green Revolution: Prioritizing 

Technologies to Achieve Energy and Environmental Sustainability.” 

February 2009: 108. 

China Huaneng Corporation, China Huadian 

Corporation and China Guodian Corporation; and 

ÆÆ four related business companies. 

Reform policy dictates that no more than 20 percent of 

the capacity in each region can be controlled by any one 

power generation company, although all power generation 

and transmission companies continue to be controlled by 

the state. The State Electricity Regulatory Commission 

(the “SERC”) was also established as part of this round of 

reforms. 

The national regulator and policy maker for China’s 

energy sector is currently the National Development and 

Reform Commission (the “NDRC”). The National Energy 

Administration, a sub-department under and supervised by 

the NDRC, was established in July 2008 to be in charge of 

national administrative work in respect to the energy sector, 

including the renewable energy industry. 

[T]he NDRC has set the goal of 

increasing the share of renewablebased 

energies to be 15 percent of 

the national generation mix by 2020. 

China has indicated it sees renewable energy as playing a 

significant part in meeting its future power demands. In its 

long-term development planning, the NDRC has set the goal 

of increasing the share of renewable-based energies to be 

15 percent of the national generation mix by 2020. 3 

Renewable Energy Law 

The Renewable Energy Law of the People’s Republic of 

China (the “RE Law”) came into effect on January 1, 2006. 

The RE Law takes the form of an umbrella document, 

3 

NDRC. “Medium and Long-Term Development Plan for 

Renewable Energy in China (Abbreviated Version, English Draft).” 

September 2007. 



providing the overarching framework of renewable energy 

policies, which are to be further detailed in ministerial-level 

legislation and eventually, provincial policy. 

The chief high-level policies touched on in the RE Law are 

the following: 

(1) Special tariffs to be set by the price authorities of the 

State Council or by public tender, with any cost above that 

of fossil fuel-based power, resulting from interconnection or 

otherwise, to be shared in a manner determined by the State 

Council; 

(2) Interest rate subsidies for the financing of renewable 

projects and tax incentives to be determined by the State 

Council; 

(3) Requirement that grid operators must connect to and purchase 

all available power from and provide related services 

to licensed renewable energy generators; 

(4) Conduct of resource surveying and development 

planning (including the setting of deployment targets) by 

the energy authorities of the State Council, with expert 

consultation; 

(5) Preference and support for renewable energy technology 

R&D and the establishment and publication of technical 

standards for renewable energy; and 

(6) The establishment of a renewable energy development 

fund to support research, pilot projects and rural 

electrification. 

Around the time the RE Law was enacted, a guidance 

document was made available titled the Renewable Energy 

Industry Development Guidance Catalogue (NDRC Energy 

[2005] No. 2517) (the “RE Catalogue”). The RE Law together 

with the RE Catalogue define renewable energy sources 

in customary terms as being wind, solar (both photovoltaic 

and concentrated), hydro, ocean (in respect to tidal and 

current movement and temperature differences), geothermal 

and biomass (including biogas). Notably, the RE law and 

Catalogue treat hydropower specially in some respects 

and expressly exclude the burning of organic material in 

low-efficiency stoves. The RE Catalogue further provides 

that government support extended under the RE Law 

would also be offered for ancillary activities such as design, 

manufacturing and support of systems, equipment, components 

and materials. 4 

The RE Law imposes many obligations on the State Council, 

which as of yet, have almost all been handled by the NDRC. 

Ambitious Development Plan 

Pursuant to the RE Law, in September 2007 the NDRC 

issued the Medium and Long-Term Development Plan for 

Renewable Energy in China (the “RE Plan”), a keystone 

policy document setting out renewable energy targets. In 

addition to the nationwide generation mix target mentioned 

above, the RE Plan sets out, among other things, nationwide 

installed generating capacity targets in 2010 and 2020 

in respect to each form of renewable energy and renewable 

portfolio standards (RPS) for the large generating 

companies. 

Targets set out in the September 2007 RE Plan 

Energy Source 2005 

(Actual) 

2010 

Target 

2020 

Target 

Renewables as a 8.0 10.0 15.0 

portion of national 

gen. mix (%) 

Hydro (GW) 117 190 300 

Wind (GW) 1.31 5.0 30.0 

Biomass (GW) 2.0 5.5 30.0 

1All ex. Biogas and n/a 4.0 24.0 

MSW (GW) 

2Biogas (GW) n/a 1.0 3.0 

3Muni. Waste (GW) n/a 0.5 3.0 

Solar (GW) 0.07 0.30 1.80 

Geothermal (annual n/a 4.0 12.0 

utilization, Mtce) 

Ocean (GW) n/a none 0.10 

Large Generation 

Company RPS (%) 

n/a 3.0 8.0 

The targets set out in the RE Plan were deemed by experts 

as highly ambitious, but now some goals have already been 

met, such as the 2010 wind power target of 5GW, which was 

met in 2008. As a result, it is likely the medium- and longterm 

targets for wind and also solar power will be revised 

4 

Neal Stender, Zhihua (David) Tang and Qingsong (Kevin) Wang. 

“Renewable Energy Law Encourages a Hundred Flowers to Bloom.” 

China Law & Practice. April 2006: 12. 



upwards 5 (rumored targets as high as 100 GW of wind and 

9 GW of solar in 2020 have appeared in recent Chinese 

press) and there is even talk of revising the nationwide 

renewables target for 2010 from 15 percent to 20 percent of 

China’s generation mix. 6 

The targets in the RE Plan are based on installed generating 

capacity rather than actual deliveries to the grid. As such, the 

large power generation companies have been concentrating 

on deploying capacity as quickly as possible to meet 

the mandated RPS, sometimes without assurance that the 

projects will be able to connect to the grid and deliver power 

in a timely fashion. 

RE Law Implementing Regulations 

Under China’s institutional framework, the State Council sets 

the country’s general policy and appropriate government 

ministries are charged with formulating the rules addressing 

issues within the national regulation framework that pertain 

to their capabilities and responsibilities. The ministerial regulations 

then guide the provincial governments as they form 

the implementing rules. Many ministerial regulations and 

provincial implementing rules have been passed to implement 

the RE Law, with more regulations expected. 

Tariff Setting and Cost Pass Through to End Users 

Viable tariffs are the most important factor for developers 

in overcoming the cost challenges attendant to renewable 

energy projects. As noted above, tariffs can be set by the 

government (feed-in tariffs) or determined through public 

tender (although the RE Law stipulates that a winning price 

is not to exceed the rate paid to grid-connected projects of 

a similar nature). The ministerial regulation covering this 

issue is the Provisional Administrative Measures on Pricing 

and Cost Sharing for Renewable Energy Power Generation 

(NDRC Price [2006] No. 7) (the “Pricing Reg”), which came 

into effect on the same day as the RE Law, January 1, 2006. 

The Pricing Reg provides the following guidelines for tariff 

determination: 

(1) Prices for biomass projects may be either feed-in tariffs 

or set by bid. For feed-in tariffs, biomass projects enjoy a 

subsidy of RMB 0.25 per kWh for 15 years following commercial 

operations. The subsidy offered to new biomass 

projects will be reduced annually from 2010 by 2 percent. 

5 

Fu Jing. “China Considers Higher Renewable Energy Targets.” 

China Daily. July 6, 2009. 

6 

Yu Tianyu. “Green Energy Attracts Investors.” China Daily. July 

10, 2009. 

Hybrid systems employing both traditional fossil-fired and 

biomass components will not receive the subsidy if over 

20 percent of the heat consumption for power production is 

from traditional sources. For tariffs set by competitive bid, 

there is no subsidy; 

(2) Solar, ocean and geothermal power projects will receive 

government-set tariffs (but detailed calculations such as 

those for biomass are not provided); 

(3) Hydropower project tariff determination is covered under 

a separate existing law; and 

(4) The “price authorities of the State Council” will be 

responsible for setting tariffs or conducting competitive bid 

processes, as applicable, in connection with renewable 

energy projects. 

The RE Law provides the added cost of developing renewable 

energy will be “shared in the selling price.” This concept 

is further detailed in the Pricing Reg, which provides that 

a renewable energy surcharge be paid by all end users of 

electricity. The surcharge may be adjusted annually and 

will cover (a) the portion of the average purchase price of 

renewable energy paid by grid operators over the average 

purchase price of energy from coal-fired projects, and (b) the 

cost of connecting renewable energy projects to the grid. 

The surcharge was initially set at RMB 0.001 per kWh by 

the Renewable Energy Surcharge Level Regulation (NDRC 

Price [2006] No. 28-33). 

Although the Pricing Reg originally provided that wind 

tariffs would be determined by competitive bid, a July 2009 

NDRC announcement revealed that as of August 1, 2009 

onshore wind projects will receive fixed tariffs of RMB 0.51, 

RMB 0.54, RMB 0.58 or RMB 0.61, depending on geographic 

region. The new benchmark tariff system effectively 

eliminates the downward pressure on on-grid prices exerted 

by bid competition and allows developers to plan wind farms 

around a known price. Tariffs for offshore projects will be 

determined separately. 

Investment Incentives 

As of yet, instruction on investment incentives has been 

limited to the generalities of the RE Law and the provision 

of feed-in tariffs and subsidies in the Pricing Reg (which are 

only really fully explained in respect to biomass projects). 

Regulations dealing solely with the special financing terms 

and tax treatment for renewable projects mentioned in the 

RE Law have not yet been passed. Recent nonrenewable 



specific regulations have touched on tax incentives for new 

renewable projects and equipment manufacturers, including: 

(1) Reduced VAT rates or whole or partial VAT rebates for 

certain types of renewable power developers 7 ; 

(2) Three-year income tax holidays with reduced (12.5 percent) 

income tax rates for the three years following expiry of 

the holiday for “basic infrastructure projects,” including hydro, 

wind, ocean, solar and geothermal power projects 8 ; and 

energy projects to connect to the grid. The second is 

the Measures on Supervision and Administration of Grid 

Enterprises in the Purchase of Renewable Energy Power 

(SERC [2007] No. 25) (the “Grid Purchase Reg”). The Grid 

Purchase Reg provides that the national grid authority and 

national standards authority draft a grid code and power 

purchase standards and that the grid operator’s purchase of 

renewable-based power will be supervised by the SERC and 

local agencies. 

(3) For certain “high and new-tech” enterprises, which may 

include equipment manufacturers, reduced (15 percent) 

income tax rates and, if incorporated in special economic 

zones, two-year income tax holidays with reduced (12.5 percent) 

income tax rates for the three years following the 

expiration of the holiday. 9 

Ensuring Grid Operator Cooperation 

Assurance that renewable energy projects will be able to 

interconnect to the grid and the enforcement of the grid 

operators’ obligation to give priority to renewable energy 

projects in grid connection and power purchase under the 

RE Law are key concerns for developers. Failure by the 

grid operators to honor their obligations can create delays, 

reduce profits and increase risks, all effective barriers to the 

commercialization of renewable energy. 

Two regulations have been 

enacted that address these 

two key components. The 

first is the Regulation on 

the Administration of Power 

Generation from Renewable 

Energy (NDRC Energy [2006] 

No. 13) (the “Administration 

Reg”), which principally provides 

that the grid operators 

are obliged to allow renewable 

7 

Notice of the Ministry of Finance and the State Administration of 

Taxation about Policies regarding the Value Added Tax on Products 

Made through Comprehensive Utilization of Resources and Other 

Products (MOF [2008] No. 156); and Notice of the Ministry of 

Finance and the State Administration of Taxation on the Application 

of Low Value Added Tax Rates and Policies on Collecting Value 

Added Tax by the Simple Approach to Some Goods (MOF [2009] 

No. 9). 

8 

Regulation on the Implementation of the Enterprise Income Tax 

Law of the People’s Republic of China. 

9 

Administrative Measures for Determination of High and New Tech 

Enterprises (MOF and SAT [2008]). 

The China Wind Energy Association 

has reported that more than 20 percent 

of China’s installed wind farms did not 

generate any power in 2008 because 

of delays in connecting to the grid. 

So far special grid codes have only been passed to provide 

technical standards for the interconnection of wind, geothermal 

and solar PV power plants. Existing regulations have 

so far proved to be insufficient and grid interconnection 

has been a serious issue for developers. The strain on the 

resources of grid operators in upgrading the grid to connect 

to renewable energy projects is proving to be too high and in 

many cases the transmission companies are not complying 

with the RE Law. The China Wind Energy Association has 

reported that more than 20 percent of China’s installed wind 

farms did not generate any power in 2008 because of delays 

in connecting to the grid. 

Government Approvals / Power Purchase Agreements 

Developers face the risk that required government approvals 

for a project in China will be costly and difficult to obtain, 

excessively delayed and 

not actually available until 

the late stages of the 

development process. To 

help mitigate these risks, a 

streamlined and transparent 

approval process is key. 

The Administration Reg 

provides that NDRC approval 

is required for renewable 

energy projects of 250 MW 

or more (or for wind projects 

50 MW or more), hydro projects located on major waterways 

and projects that require state policy or funding support. 

Other projects may be approved by the development and 

reform commission offices at the province level. In addition, 

compliance is needed from the grid operators in order to 

connect and sell power to the grid, which as noted above, is 

not always timely (notwithstanding the grid operator’s connection 

and purchase obligations under the RE Law and the 

Administration Reg). Other standard types of project approvals, 

including in respect to foreign investment, if applicable, 

will be required. 



Also of concern for developers is the document that memorializes 

the agreement between the developer and the grid 

operator with respect to the sale and purchase of power. As 

of yet, model power purchase agreements` have not been 

published. 

Recent Solar Announcements, Proposed Amendments 

to the RE Law and Market Outlook 

Several key recent announcements have made investment 

in solar projects more interesting and indicate that the 

government is now turning its attention to solar after its initial 

focus on wind power. First, in March 2009, the Ministry of 

Finance (“MOF”) announced the government would provide 

subsidies of RMB 20 per watt generated during peak hours 

by solar projects attached to buildings with capacities of 

greater than 50 kW. Then, in July 2009, the MOF announced 

that government subsidies would be offered for 50 percent 

of the investment in grid-connected solar power projects 

and 70 percent of the investment in remote, off-grid solar 

power projects. To qualify, the projects must have generating 

capacities of more than 300 kW, be completed in one 

year and be operative for at least 20 years. 10 Although the 

MOF announcements are light on detail and some unanswered 

questions remain in respect to the subsidies and 

feed-in tariffs for solar PV projects, the September 2009 

announcement that U.S. firm First Solar Inc. plans to build 

a 2 GW solar power plant complex in Inner Mongolia is a 

strong sign that developers are responding to the favorable 

investment environment cultivated by the PRC. 11 An NDRC 

10 

Jim Bai and Leonara Walet. “China Offers Bid Solar Subsidy.” 

Reuters. July 21, 2009. 

11 

“U.S. Firm Says it Will Build China’s Largest Solar Energy Plant.” 

China Daily: September 14, 2009. 

announcement which addresses outstanding solar PV concerns 

is expected sometime before the end of 2009. 

The NDRC has recognized the power transmission upgrade 

bottleneck which is preventing many projects from being able 

to connect to the grid. A draft amendment to the RE Law has 

been submitted to the Standing Committee of the National 

People’s Congress. The draft has not been disclosed to the 

public, but reports indicate that the amendments will focus 

on measures designed to directly or indirectly accelerate grid 

development, such as (1) establishing a government fund to 

support R&D of renewable energy and smart grid technology; 

(2) requiring ministries to formulate concrete plans for 

meeting China’s medium and long-term renewable energy 

development targets; and (3) setting a nationwide annual 

purchase quota for renewable energy. 12 

Additional areas of concern for developers that could be 

further addressed in guidance regulations include tax 

incentives, tariff-setting methods for ocean and geothermal 

energy, special loan arrangements, grid codes for certain 

types of energy and resource assessment methodology. 

As legislation continues to be passed, the picture will 

become clearer for developers. The enactment of the Energy 

Conservation Law on April 1, 2008, the endorsement of 

a climate change resolution on August 27, 2009 and the 

imminent passage of the new Energy Law, which is under 

discussion and expected to be enacted in the near future, 

and several other policy and legislative developments do and 

will continue to underpin government commitment to renewable 

energy development, and developers should certainly 

take note. 

12 

Li Jing. “China Plans for Renewable Energy”. China Daily: 

August 25, 2009. 



Renewable Energy Development Prospects of Southeast Asia’s 

‘Green Tigers’ 

The nations of Southeast Asia have some of the most 

abundant renewable energy resources in the world. As 

governments formulate policy reforms to encourage the 

development of renewable energy, we take a look at the 

markets and regulatory regimes in three countries that could 

be set to take off: the Philippines, Indonesia and Thailand. 

The Philippines 

More than 10 years after the act had first been introduced, 

the Philippine legislature finally enacted the Republic Act 

No. 9513 or the Renewable Energy Act of 2008 (the “RE 

Act”), a landmark piece of legislation providing a regulatory 

framework for the renewable energy industry, which could 

make the Philippines one of the first Southeast Asian nations 

to have a renewable energy market as sophisticated as the 

United States, Germany, Spain and other developed nations. 

Renewable Energy Sector Background 

To date most renewable energy efforts in the Philippines 

have related to hydro and geothermal power. At the end 

of 2007, the total electricity-generating capacity of the 

The Philippines is the world’s secondlargest 

producer of geothermal 

power, with a current generating 

capacity of 1,900 MW. 

archipelago nation was 15,937 MW. Hydropower constituted 

20.64 percent of the generation mix, geothermal 

12.29 percent and other types of renewable energy less than 

1 percent. 1 The Philippines is the world’s second-largest 

producer of geothermal power, with a current generating 

capacity of 1,900 MW. 2 

In addition to hydro and geothermal, the government also 

sees other forms of renewable energy as being an important 

1 

“Power Sector Situationer, 2007.” Philippine Department of 

Energy website. Accessed July 2009. http://www.doe.gov.ph/EP/ 

powerstat.htm 

2 

“Philippines Data Page” International Geothermal Association 

website. Accessed July 2009. http://www.geothermal-energy.org/ 

geoworld/geoworld.php?sub=map&region=asia&country=philippines 

part of its future energy mix. With over 7,000 islands, 

electrifying outer-lying rural communities is a serious issue. 

Small-scale solar, wind and micro-hydro generators are 

ideal for villages located in far-flung areas where connecting 

to regional grids would be prohibitively expensive. The 

Department of Energy (the “DOE”) has stated plans to 

develop these and other renewable energy sources in the 

Philippines’ Power Development Plan 2004-2013. 

Renewable Energy Act 

On December 16, 2008, more than a decade after it was 

first introduced, President Gloria Arroyo signed and thereby 

passed into law the RE Act. The RE Act generally provides 

incentives and increased grid and market access for renewable 

energy projects, while also, among other things, setting 

policies for rural (off-grid) electrification and a green pricing 

mechanism to promote the consumer’s option to purchase 

power generated from renewable sources. 

Regulatory Structure 

The RE Act establishes a formal regulatory structure for the 

renewable energy industry. The National Renewable Energy 

Board (the “NREB”), a president-appointed advisory panel 

created under the RE Act to oversee its implementation, 

comprises industry stakeholders, including representatives 

from concerned governmental departments, developers, 

distribution utilities, government financial institutions, NGOs 

and others. The Renewable Energy Management Bureau 

(the “REMB”), a sub-department under the DOE also created 

under the RE Act, is charged with carrying out the information 

dissemination, research, monitoring and supervision 

functions made necessary by the policies outlined in the RE 

Act. The IRR (defined below) appoints the DOE to be lead 

agency mandated to implement the RE Act’s provisions. 

The RE Act also establishes the Renewable Energy Trust 

Fund to be administered by the DOE as a special account for 

government financial institutions such as the Development 

Bank of the Philippines, the Land Bank of the Philippines, 

the Philippine Export-Import Credit Agency (“PhilEXIM”) and 

others. The fund is to support the development of renewable 

energy by providing capital to finance R&D (especially 

the development of new resources to maintain national 

competitiveness), conduct nationwide resource and market 

assessment studies, and support knowledge accrual by 

providing grants to research institutions. 



Implementing Rules and Regulations (IRR) 

The DOE issued the department circular titled the 

Implementing Rules and Regulations (IRR) of Republic Act 

No. 9513 (the “IRR”) on May 25, 2009. The IRR sets out 

clear, detailed guidelines as to how each of the high-level 

policies of the RE Act are to be carried out. In addition to providing 

regulations for the development of renewable energy 

resources, the IRR also clarifies the responsibilities of the 

government entities to be involved in the renewable energy 

industry and their relationship to the NREB. 

Key Policies Further Detailed in the IRR 

Employing the framework set out in the RE Act, the IRR 

restates key policies, names the entities responsible for carrying 

them out and provides time frames for their completion. 

Detailed rules are to be formulated, reviewed and enacted 

within one year of the passage of the RE Act in most cases. 

Key policies mentioned in the RE Act and further detailed in 

the IRR include: 

(1) the creation of renewable portfolio standards (RPS) 

pursuant to which power generators, distribution utilities and 

suppliers must source or produce a certain percentage of 

their electricity from renewable-based sources; 

(2) the establishment of feed-in tariffs and priority privileges 

to be enjoyed by generators employing certain types of 

renewable resources (notably, not geothermal) for at least 

12 years; 

(3) the development of a net-metering protocol, whereby 

qualified end users may connect and supply power to the 

grid (including small-scale home and office solar PV units) 

to be netted against electricity delivered by the distribution 

utility; and 

(4) the formation of a renewable energy market for the trading 

of “RE Certificates.” 

Incentives for Developers and Other Renewables 

Stakeholders 

As is true elsewhere in the world, the generation of electricity 

in the Philippines from renewable resources is an expensive 

proposition. To help offset the requisite exploration and/or 

technology costs, the IRR details a comprehensive set of 

incentives to entice investors to develop renewable projects 

and reward those who have invested in existing renewable 

projects. 

The incentives are offered to developers possessing a 

Certificate of Endorsement issued by the DOE through the 

REMB, including developers of hybrid systems utilizing both 

renewable- and non-renewable-based energy sources, in 

proportion to and to the extent of their project’s renewable 

energy component. 

Incentives include the following: 

(1) Seven-year income tax holiday, available for new or 

existing projects, in each case starting from the commercial 

operations date. New and additional investments in an existing 

project also qualify for this, but only in respect to income 

attributable to the new investment and any one project may 

not enjoy the tax holiday for more than 21 years; 

(2) Duty-free import of machinery and equipment needed 

for the project (regardless of whether the same is available 

in the Philippines) for 10 years from the registration of the 

project; 

(3) Special realty tax rate of 1.5 percent on net book value of 

civil works, equipment, machinery and other improvements 

used for renewable energy facilities; 

(4) Carryover of net operating loss from the first three years 

of commercial operations as a deduction from gross income 

for the next seven consecutive taxable years; 

(5) Corporate tax rate of 10 percent after expiration of the 

income tax holiday (or for qualified existing projects, upon 



the effectivity of the RE Act), provided that the developers 

pass on the savings to end users in the form of lower rates; 

(6) For projects failing to receive an income tax holiday 

before full operations, accelerated depreciation at twice the 

normal rate; 

(7) Zero percent value-added tax on the sale of power or 

fuel from renewable sources; the purchase of local goods, 

properties and services for project development purposes; 

and payment for services in connection with the exploration 

and development of renewable sources; 

(8) Tax-free sale of carbon emission credits; and 

(9) Tax credit equivalent to 100 percent of the value-added 

tax and customs duties that would have been paid on 

machinery, equipment, materials and parts purchased locally 

had they been imported, provided that the purchase is made 

from a DOE-approved Philippine supplier. 

In addition to incentives offered to developers, the IRR 

goes on to detail incentives for manufacturers of renewable 

energy generation equipment and farmers who plant 

biomass resources, as well as incentives for end users to 

promote rural electrification and the use of net metering. 

Resource Development Contracts and Foreign Investor 

Limitation Controversy 

The IRR provides that all sources of potential energy are 

owned by the state and that each developer must enter 

into a Renewable Energy Service/Operating Contract (“RE 

Contract”) with the government (through the president or 

the DOE) under which the developer will have an exclusive 

right to explore and develop a particular area for a specified 

period. The RE Contract may have a term of up to 25 years 

(renewable for up to 25 years) and will cover two stages: 

pre-development (preliminary assessment and feasibility 

study up to financial close) and development (construction 

and installation of facilities up to operations). As consideration 

for granting the exclusive right to utilize Philippine 

natural resources to the developer, the government 

receives 1 percent (or 1.5 percent in case of geothermal RE 

Contracts) of the gross income received by developers attributable 

to sale of renewable energy. This “Government Share” 

is split, with 60 percent to go to the national government and 

40 percent to the local government. The Government Share 

is not collected for biomass projects or projects on a micro 

scale less than 100kW. 

The DOE has provided some further detail on RE Contracts 

in its circular titled Guidelines Governing a Transparent 

and Competitive System of Awarding Renewable Energy 

Service/Operating Contracts and Providing for the 

Registration Process of Renewable Energy Developers (the 

“Guidelines”), issued on July 12, 2009. Under the Guidelines, 

RE Contracts can be awarded by competitive bid or by direct 

negotiation or arrangements for existing projects can be converted 

to RE Contracts in order for the projects to avail of the 

incentives provided under the RE Act. Direct negotiation can 

only be used to award new RE Contracts if there is only one 

applicant for a project or for areas for which there is limited 

technical data (dubbed ‘Frontier Areas’). 

Under the IRR and the Philippine Constitution, RE Contracts 

may only be entered into by Filipino citizens or corporations 

or associations at least 60 percent of whose capital is 

owned by Filipinos, although a special exemption is made 

for large-scale geothermal contracts under the Guidelines. 

The Joint Foreign Chambers of Commerce in the Philippines 

have expressed disapproval at this limitation on foreign 

developer investment in wind, solar and ocean energy and 

have requested a review of the interpretation of the IRR and 

the Constitution on the grounds that this limitation seems 

to conflict with the policy objectives at the heart of the RE 

Act. 3 There is also some controversy as to whether allowing 

wholly foreign corporations to invest in geothermal projects 

under the Guidelines is in fact constitutional. 4 

Looking Forward 

As noted above, within the next year or so the rules and 

regulations outlined in the IRR will be formalized, concerns 

surrounding foreign investment will likely be addressed 

and the picture will become clearer for developers. The 

response from the private sector has already been positive; 

the Philippine Star reported on July 14, 2009, that there are 

now over 100 renewable energy projects in the pipeline for 

investors influenced by the attractive incentives offered by 

the RE Act. 

Indonesia 

The government of geothermal resource-rich Indonesia has 

recently announced a second phase of its “crash program” 

3 

Ben Arnold O De Vera. “Equity Cap on Energy Projects Antiinvestor.” 

Manila Times. August 27, 2009. 

4 

Myrna M. Velasco “Foreign Investors Bat for Clarity in 

Re-Classification of Geothermal as RE Resource.” Manila Bulletin. 

September 9, 2009. 



whereby it expects to develop 10 GW of installed generating 

capacity by 2014. A large portion of this has been set 

aside for geothermal power plants. The government will 

offer up most of the projects to private investors, and some 

projects have already been awarded. This section provides 

a brief history of geothermal development and legislation 

in Indonesia to date, and describes certain obstacles that 

discourage developers from investment. 

Abundant Resources, But Limited Development 

The Ministry of Energy and Mineral Resources (“EDSM”) 

has estimated that Indonesia has the geothermal resources 

to develop more than 27,000 MW of installed generating 

capacity. 5 As of July 2009, however, just 1,057 MW of 

geothermal-based capacity had been developed. 6 

Currently government representatives estimate that renewable 

energy represents roughly 4.5 percent of Indonesia’s 

generation mix (roughly 3 percent being hydro and 1.5 

percent being geothermal based). 7 

Regulatory Structure 

In Indonesia, EDSM is charged with formulating energy 

policy. PT Perusahaan Listrik Negara (“PLN”) is the state 

power transmission, generation and distribution enterprise. 

Geothermal resource development and electricity production 

may be undertaken by the public or private sector. 

PT Pertamina (“Pertamina”), the state-owned oil and gas 

company, has previously acted as the regulator, as well as 

a developer, for geothermal exploitation and remains a key 

player in the industry. 

Renewable Energy Plans 

Indonesia has passed several laws intended to facilitate the 

development of renewable energy technologies. A recent 

piece of legislation, Presidential Decree No. 5/2006 (the 

“Energy Plan”), demonstrates Indonesia’s commitment 

to develop renewable energy-based power generation. 

The Energy Plan sets out targets for the energy sector in 

2025, namely setting the goal that renewables account for 

17 percent of Indonesia’s installed generating capacity (with 

5 

“Indonesia has 27,000 MW of Potential Geothermal Energy 

Sources.” Antara News. November 12, 2007. 

6 

“Wayang Windu II Geothermal Powerplant Begins Operation.” 

EDSM Press Release. June 22, 2009. 

7 

Montty Girianna. “Renewable Energy and Energy Efficiency 

in Indonesia.” ADB Workshop on Climate Change and Energy, 

Bangkok. March 26–27, 2009: 1. 

5 percent to come from biofuel; 5 percent from geothermal; 

5 percent from a combination of biomass, hydro, solar, wind 

and nuclear; and finally 2 percent from liquefied coal). 

Previous Geothermal Program and Geothermal 

Legislation 

The government has recognized the country’s tremendous 

geothermal potential for quite some time. In 1991 the first 

geothermal program was introduced by which public and 

private enterprises would be allowed to participate in the 

development of geothermal-based resource exploitation and 

electricity generation. At that time Pertamina was the entity 

responsible for managing geothermal resources for the government. 

The implementing regulation for the campaign was 

Presidential Decree No. 45/1991, by which 11 joint operating 

contracts were granted to private developers to exploit as 

The Ministry of Energy and Mineral 

Resources has estimated that Indonesia 

has the geothermal resources to 

develop more than 27,000 MW of 

installed generating capacity. 

much as 3,000 MW of geothermal power. Other fields with 

estimated capacity of 1,500 MW were allotted to Pertamina 

for development. Most projects were derailed by the 1997 

Asian financial crisis, and as a result, only a small fraction 

of Indonesia’s geothermal potential has been developed to 

date. 

Each of the projects that was completed operates under 

one of two different schemes. The first is that Pertamina or 

its joint operation contractor operates the steam production 

facility and sells steam to PLN or others that generate 

electricity using their own plants. The alternative is that 

Pertamina or its joint operation contractors operate both the 

steam facility and the power facility, with electricity being sold 

off to PLN or others. 

Private developers participate by operating the steam 

production fields, and in some cases the power generation 

facilities, under Joint Operation Contracts with Pertamina as 

resource holder. Power is purchased by PLN under dollar- 



denominated Energy Sales Contracts on a take-or-pay basis 

for 30 years or more. Electricity tariffs offered for the 1991 

program were between 7 and 8 U.S. cents/kWh (most later 

renegotiated). The government receives compensation for 

the exploitation of the steam resource via royalties calculated 

at 34 percent of net operating income under the power 

offtake agreement. 8 

During the economic turmoil in the years following the 

financial crisis, geothermal contracts for private developers 

were suspended and later renegotiated or cancelled. Those 

projects that were already producing power eventually renegotiated 

lower tariffs under the existing contracts. Others that 

had not yet developed the steamfields opted to transfer the 

assets back to the government by arbitration or cancellation 

of contract. 

After several years of no geothermal development, the 

government sought to reignite the geothermal program with 

the passage of Law No. 27/2003 (the “Geothermal Law”) 

on October 22, 2003. The Geothermal Law shifts regulatory 

authority from Pertamina to EDSM, requires that future 

steamfields (not awarded under the 1991 program) must 

be competitively bid out and also provides that provincial 

governments (not the central government) are responsible 

for confirming the existence of geothermal resources by 

surveying and drilling. The Geothermal Law allows developers 

that were awarded fields in the 1991 program to retain 

control of the development rights. It should be noted that 

the Geothermal Law provides high-level policies, and few 

implementing rules and regulations have been implemented 

to date. 9 

Two recent regulations, Government Regulation No. 59/2007 

and Ministerial Regulation No. 14/2008 (“Geothermal Price 

Regulations”), have further detailed that the electricity tariff 

for geothermal power plants will vary based on capacity: 

plants greater than 55 MW will receive 85 percent of PLN’s 

production cost, plants greater than 10 MW but less than 

55 MW will receive 80 percent, and the tariff for smaller 

plants will be provided for under separate regulations. 

8 

“Indonesia’s Geothermal Development,” U.S. Embassy Jakarta 

website. Accessed July 2009. http://www.usembassyjakarta.org/ 

download/geo2002.pdf 

9 

World Bank. “Project Appraisal Document on a Proposed Global 

Environment Facility (GEF) Grant of a US$4 Million to the Republic 

of Indonesia for a Geothermal Power Generation Development 

Project.” May 1, 2008: 86–87. 

The Second 10 GW Crash Program and Expected 

Geothermal Rate Ceiling 

Faced with a dangerously low power reserve capacity, in 

2007 Indonesia announced plans for a “crash program” to 

construct installed coal-fired generating capacity of 10 GW 

by 2010. The government has now announced that a second 

crash program will be carried out with another 10 GW to be 

added to the grid from 2009 to 2014. Of this new capacity, 

4,733 MW will be geothermal. 10 

In June 2008 EDSM tendered bids for three West Java 

geothermal projects: the 220 MW Tangkuban Perahu, 

45 MW Cisolok Sukarame and 50 MW Tampomas. Bids 

from 17 companies, including Chevron and Medco Energi 

International, were received. 11 American firm Raser 

Technologies, Inc., was awarded the Tangkuban Perahu 

project. 12 The winners of the other two projects have not yet 

been publicly identified. 

EDSM announced in August 2009 that PLN would soon set 

a ceiling on rates it would pay privately owned geothermal 

power plants in order to encourage investment by resolving 

tariff uncertainties. PLN plans to determine an appropriate 

ceiling price without the help of an independent advisor and 

the price will vary based on project capacity and location. 13 

Recent Indonesian press has reported the ceiling price may 

be between 6.5 and 7 US cents/kWh. 14 

Barriers to Geothermal Development 

Even with some legislation in place for the development of 

geothermal-based power generation and the announcement 

of the second crash program, there are still several obstacles 

for developers and PLN alike. First, there are some fundamental 

deficiencies in the bid tender process for geothermal 

projects that some companies may exploit. Bidders are not 

required to post a bid bond or agree to a Power Purchase 

Agreement (“PPA”) prior to bid submission, so winning bidders 

have limited contractual obligations and financial stake 

10 

Girianna 1. 

11 

Ika Krismantari. “Chevron, Medco to tap RI geothermal 

potential.” Jakarta Post. June 17, 2008. 

12 

“Raser Wins West Java Geothermal Development Concession.” 

Raser Technologies, Inc. Press Release. http://www.rasertech. 

com/geothermal/raser-wins-west-java-geothermal-developmentconcession 

September 3, 2008. 

13 

Yessar Rosendar. “PLN to Put a Cap on Geothermal Prices.” 

Jakarta Globe. August 17, 2009. 

14 

Reva Sasistiya. “Star Energy to Push PLN for Big Hike in Price 

of Geothermal Energy.” Jakarta Globe. September 15, 2009. 



in developing a geothermal project awarded to them. The 

lack of a standard, published PPA also can lead to lengthy 

contract negotiations. Second, the Geothermal Law shifted 

the onus of confirming geothermal resource areas onto 

provincial governments, which may not possess the funding 

and expertise to carry this out, often leading to poor resource 

data. 15 Third, the high up-front costs required to develop the 

steam resource can represent a major risk, because it is 

usually difficult to determine if a particular field will generate 

sufficient steam to power a generating plant for the 30-plus 

years necessary to recoup the initial investment. 16 The 

guarantee of a set power offtake price should mitigate this 

somewhat. Finally, as noted above, a robust set of implementing 

rules and regulations for the Geothermal Law has 

not yet been put in place, so there is still some uncertainty 

in respect to bid processes, the role of central and provincial 

governments, and other issues. 

Conclusion 

It is clear that Indonesia has a massive potential to develop 

renewable energy, particularly geothermal-based energy. 

The government recognizes this and has set lofty goals for 

geothermal-based power generation. With the expected setting 

of a rate ceiling for private geothermal projects, the price 

uncertainty standing in the way of investor involvement may 

soon be removed and investors have shown significant interest, 

but it remains to be seen whether the projects are now 

“bankable” under existing legislation. 

Thailand 

Thailand has had legislation and policy in place to support 

renewable energy development for some time, but has yet 

to utilize renewable resources for a significant portion of its 

power generation. In July 2007 Thailand had an installed 

generating capacity of roughly 28.5 GW. 17 Approximately 

13.2 percent of that capacity was hydropower (mostly large 

scale, which is generally excluded when discussing renewable 

energy sources under Thailand’s energy policy) and 

1 percent was based on renewable sources. 18 

15 

Girianna 5–6. 

16 

Andrew Symon. “Indonesia Gets into Hot Water.” Asia Times. 

May 15, 2008: 3. 

17 

Including plants in Laos and Malaysia that sell power to Thailand 

under long-term PPAs. 

18 

Prutichai Chonglertvanichkul. “Thailand Power Development 

Plan (PDP 2007)” High Level Forum on Lao-Thai Partnership in 

Sustainable Hydropower Development, Bangkok: September 7, 

2007. 

SPP and VSPP Program Background 

Although renewable energies currently represent a small 

portion of Thailand’s generation mix, the Kingdom has indicated 

that it would like to scale back its reliance on natural 

gas (currently over 60 percent of generation capacity is 

gas-based) and address climate change by encouraging the 

development of renewable energy-based power generation. 

To serve this end, Thailand’s Small Power Producer (“SPP”) 

Program was introduced in 1992. It currently covers power 

developers wishing to sell power to the grid in a range of 10 

MW to 90 MW. The regulations governing the SPP Program 

were modeled after the Public Utility Regulatory Policies 

In July 2007 Thailand had an installed 

generating capacity of roughly 

28.5 GW. Approximately 13.2 percent 

of that capacity was hydropower. 

Act (PURPA) implemented in the U.S. in 1978. 19 The SPP 

Program was re-launched in 2007 with the passage of regulations 

for cogeneration, renewables and “non-firm” projects 

(the “SPP Regulations”). In January 2009, the National 

Energy Policy Council (the “NEPC”) announced the approval 

of the revised Power Development Plan, which provides for 

the SPP bidding of roughly 2,000 MW, with construction to 

begin in 2010 and finish in 2013. 

Generally, SPPs can be classified as “firm” or “non-firm” 

based on their obligations under PPAs to deliver power to 

the Electricity Generating Authority of Thailand (“EGAT”), 

the national utility. By regulation, firm SPPs are required 

to meet capacity, reliability, availability and delivery obligations 

and are rewarded therefore with capacity payments in 

addition to energy payments. In contrast, non-firm SPPs are 

not required to meet these obligations and are paid only for 

power actually delivered to the offtaker. 

Building on the success of the SPP Program, the Very Small 

Power Producer (“VSPP”) Program was introduced in 2002 

to provide procedures for small self-sustaining business 

operations in rural and remote areas to sell power of 1 MW 

or less to the grid to offset their power consumption costs. 

19 

Dr. Piyasvasti Amranand. “Alternative Energy, Cogeneration 

and Distributed Generation: Crucial Strategy for Sustainability of 

Thailand’s Energy Sector.” 



The program was re-launched in 2006 to increase the 

capacity for eligible VSPPs to above 1 MW, but not exceeding 

10 MW. VSPP PPAs are non-firm, and VSPPs receive 

payment for power actually delivered under a “net-metering” 

mechanism. VSPP regulations consist of regulations for 

cogeneration projects, regulations for renewables projects 

and synchronization regulations (the “VSPP Regulations”), 

and are based on net-metering laws in the U.S. and other 

countries. 20 

When first introduced in 1992, the SPP Program allowed 

for generation by combined heat and power (cogeneration) 

methods or the utilization of renewable-based energy 

sources. During the first six years or so, the program saw 

applications mainly for cogeneration projects. When the 

Asian financial crisis crippled Thailand’s power demand and 

precipitated an excess reserve capacity, the Thai Cabinet 

granted a 1998 ruling providing that EGAT no longer needed 

to accept new cogeneration projects. After a rush to sign up 

cogeneration projects before the ruling took effect, EGAT 

has since almost exclusively accepted renewable projects, 

mainly large biomass-based plants. One impetus for this 

shift in policy was a common complaint from EGAT and 

SPPs alike that steam use efficiency requirements were too 

lax, resulting in little to no gain in efficiency over traditional 

combined cycle gas turbine projects. 21 

From the launch of the VSPP Program in 2002, a much 

wider range of energy sources was incorporated than under 

the SPP Program. Whereas under the SPP Program the 

majority of projects utilized gas- or coal-fired cogeneration 

rather than renewable sources, the majority of applicants for 

the VSPP Program were pig farms, food processing plants 

and other small-scale rural businesses producing organic 

waste that could be used to fuel power generation. 22 Under 

the VSPP Regulations as originally issued in 2002, VSPPs 

could generate electricity from renewable sources, such as 

solar, wind, micro-hydro, biogas and biomass. Part of the 

2006 re-launch was an expansion of the VSPP Program to 

include clean fossil-fired cogeneration plants, with efficiency 

requirements based on Germany’s cogeneration program, 

which are more stringent than those of the SPP Program. 23 

As of April 2008, there were 61 SPPs in operation, supplying 

2,286 MW of power to EGAT. Taking into account power 

offtake by industrial customers located near the SPP plants, 

the total installed capacity of the SPPs was 3,877 MW. As of 

June 2008, there were 100 VSPPs supplying 215 MW to the 

grid, with total installed capacity of 540 MW. 24 

Regulatory Provisions and Model Power Purchase 

Agreements 

From time to time, the Energy Policy and Planning Office 

makes publicly available model standard form PPAs to be 

used for SPP and VSPP projects. These, together with the 

SPP and VSPP Regulations, form the legislative basis for 

the programs. SPP PPAs are made between the SPP and 

EGAT. Conversely, VSPPs contract directly with one of two 

national distribution companies, Metropolitan Electricity 

Authority (“MEA”) for projects situated in Bangkok or 

Provincial Electricity Authority (“PEA”) for projects located in 

other provinces. 

SPPs may also execute bilateral PPAs with industrial customers 

located in the vicinity of the power plant. This practice 

is common within Thailand’s industrial estates. 

The SPP Regulations for firm SPPs reference contract terms 

of 20 to 25 years. The term for non-firm SPPs under the 

SPP Regulations is one year from commercial operations, 

and may be renewed for an indefinite number of additional 

periods of one year each by notice from one party to the 

other party. 

The initial term of the VSPP PPAs commences on the signing 

date and continues for one-year periods up to five years. 

The term automatically renews on a continuing basis, each 

time for an additional period equal to the duration of the initial 

term. The number of renewals is indefinite, and only the 

VSPP may unilaterally terminate the PPA where there is no 

breach of the agreement. 

SPP PPAs and VSPP PPAs are governed by Thai law. 

20 

Chris Greacen. “An Emerging Light: Thailand Gives the 

Go-Ahead to Distributed Energy.” Cogeneration and On-Site Power 

Production. March–April 2007: 68. 

21 

Greacen 66. 

22 

Dr. Pallapa Ruangrong. “Thailand’s Approach to Promoting 

Clean Energy in the Electricity Sector.” Forum on Clean Energy, 

Good Governance and Regulation, Singapore: March 16–18, 

2008: 1. 

23 

Greacen 70. 

24 

Amranand 6. 



Current Adders and Adders Proposed at NEPC Meeting 24 

Tariff Subsidies for Renewable Projects 

partly due to its clear policy on renewable energy. 25 

In May 2001, as encouragement for developers to build and 

operate costly renewable-energy-based generation facilities, 

an incentive program was introduced whereby certain SPPs 

supplying renewable-based energy in Thailand enjoy a per 

kWh incentive or “adder” based on actual amount of energy 

supplied to the grid. In mid-2002 MEA and PEA announced 

Project 

Type and 

Size 

Current 

Adder 

(Baht / 

kWh) 

New 

Adder 

(Baht / 

kWh) 

Special 

Adder** 

(Baht / 

kWh) 

Special 

Southern 

Adder*** 

(Baht / 

kWh) 

similar adder schemes for the VSPP Program. Several modifications 

1.Wind 

to the adder programs for both SPPs and VSPPs 

< = 50 kW 3.50 4.50 1.50 1.50 

have since been introduced (almost all being positive for the 

> 50 kW 3.50 3.50 1.50 1.50 

developer). 

2. Solar 8.0 8.0 1.50 1.50 

Eligibility for the adder is based on location, size and type of 

fuel or energy source. Wind and solar projects receive the 

3. Biomass 

< = 1 MW 0.30 0.50 1.00 1.00 

highest adders, followed by hydro (micro and mini), biomass, 

> 1 MW 0.30 0.30 1.00 1.00 

biogas and waste. To compensate developers for a higher 

4. Biogas 

degree of risk in Thailand’s three southernmost provinces, 

< = 1 MW 0.30 0.50 1.00 1.00 

Yala, Pattani and Narathivath, due to political unrest, special 

adder rates are offered for renewable energy SPPs and 

> 1 MW 0.30 0.30 1.00 1.00 

VSPPs developed in these provinces. 

5. Municipal Waste 

Landfill / 2.50 2.50 1.00 1.00 

On March 9, 2009, the NEPC approved a proposal to further Gasification 

increase adder rates for certain types of projects and offer 

Thermal 2.50 3.50 1.00 .100 

a new special adder for renewable energy projects located 

Process 

in the vicinity of diesel-fired plants (which are considered 

6. Mini / Micro Hydro Power 

undesirable due to high fuel cost and emissions). 

50 kW 0.40 0.80 1.00 1.00 

Adder rate changes for SPPs took effect on August 4, 2009, 

under an EGAT Declaration and for VSPPs on August 19, 

- 200kw 

< 50kw 0.80 1.50 1.00 1.00 

2009 under separate Notifications from MEA and PEA. 

* For projects located in an area generating electricity from 

Looking Forward 

diesel. 

Thailand’s renewables future is bright and interest from 

** For projects located in one of three southern border 

developers in the latest SPP bidding round has been high. 

provinces. 

In response to the announcement and enactment of the new 

adders, plans for Thailand’s first privately developed industrial 

scale solar and wind projects have been announced. No 

24 

Energy Policy and Planning Office. “Summary of Improvement 

doubt this interest will be further bolstered by the announcement 

in July 2009 that the World Bank and International Energy” trans. Palida Rattanawiboon. 

of Guidelines for Promoting Electricity Generation from Renewable 

Finance Corporation will make available US$700 million in 

low-interest loans to develop clean energy projects. Thailand 

was the first of 10 countries selected to receive the support, 

25 

Yuthana Praiwan. “World Bank to Give Clean 

Energy Gift.” Bangkok Post. July 14, 2009. 



Recovery Act Guidance Update 

Treasury Grant Program 

On July 9, 2009, the U.S. Treasury Department (“Treasury”) 

released guidance related to the Treasury Grant program 

enacted under Section 1603 of the American Recovery and 

Reinvestment Tax Act of 2009. Generally, Section 1603 

provides a 10 percent or a 30 percent cash grant in lieu of 

investment tax credits for certain renewable energy facilities 

that are (a) placed in service in 2009 or 2010 (regardless of 

when construction began) or (b) placed in service after 2010 

but before the applicable placed-in-service deadline for such 

facility, but only if the construction of such property began 

during 2009 or 2010. The Treasury Grant is available only 

for property that is used in a trade or business or held for the 

production of income. Accordingly, nonbusiness energy property 

and residential energy-efficient property eligible for tax 

credits under Section 25C and 25D of the Internal Revenue 

Code (the “Code”) do not qualify for a Treasury Grant. 

This article is only a summary of certain aspects of the 

Treasury Grant program guidance. Complete details regarding 

the application process and the program guidance are 

available at http://www.treasury.gov/recovery/1603.shtml. 

Application. In addition to the program guidance, the 

Treasury also released an application and other related 

documents. Applications must be submitted online at https:// 

treas1603.nrel.gov/. For property placed in service in 2009 or 

2010, an application cannot be submitted for a project until 

after the project is placed in service, and must be submitted 

before October 1, 2011. For projects that are under construction 

in 2009 or 2010, but not placed in service until after 

2010, applications must be submitted after construction has 

begun, but before October 1, 2011. 

Payment of the cash grant will be made within 60 days 

from the later of (a) the date of the completed application or 

(2) the date the property is placed in service. For projects 

that are not placed in service when the application is submitted, 

the application process may include two stages (an 

initial application and supplemental information). 

Certain documentation must be submitted with the application 

to demonstrate that the property is eligible property that 

has been placed in service or, if placed in service after 2010, 

that construction began in 2009 or 2010. The types of documentation 

that must be submitted depend on the type of and 

other facts relating to the facility. 

Eligible Applicants. Certain entities are not eligible for 

Treasury Grants, including (a) federal, state or local governments 

(or any political subdivision, agency or instrumentality 

thereof), (b) any organization described in Section 501(c) of 

the Code and exempt from tax under Section 501(a) of the 

Code, (c) any entity described in Section 54(j)(4) of the Code 

or (d) any partnership or other pass-thru entity that has any 

of the entities described in (a) through (c) above as a direct 

or indirect partner, unless such ineligible entity owns an indirect 

interest in the applicant-partnership through a taxable C 

corporation. The guidance clarifies that a foreign person or 

entity is eligible for a cash payment if at least 50 percent of 

the income of the person or entity (or shareholder) is subject 

to U.S. income tax (the exception provided under Section 

168(h)(2)(B) of the Code). 

Beginning of Construction. When construction begins is 

important for projects on which construction begins in 2009 

or 2010 but the project is not placed in service until after 

2010. It has no impact on projects in which construction 

began before 2009, if those projects are indeed placed in 

service in 2009 or 2010. 

The guidance provides that construction begins when physical 

work of a significant nature begins and provides a safe 

harbor rule. In the case of self-constructed property (the 

applicant manufactures, constructs or produces property 

for its own use in a trade or business or for the production 

of income), construction begins when physical work of a 

significant nature begins. Physical work does not include 

preliminary activities (planning, designing, securing financing, 

exploring, researching, clearing site, test drilling, etc.). 

The guidance provides, for example, that construction 

begins when work begins on the excavation for a foundation, 

the setting of anchor bolts into the ground or the pouring of 

concrete foundations. If the energy property is assembled 

from modular units off-site, construction begins when physical 

work of a significant nature commences at the off-site 

location. 

In the case of property that is manufactured, constructed or 

produced for the applicant by another person under a written 

binding contract, construction begins when physical work of 

a significant nature begins under the contract. A contract is 

a binding contract if it is enforceable under state law against 

the applicant, does not limit damages to an amount less than 



five percent of the total contract amount, and various other 

requirements. 

In the case of either self-constructed property or property 

constructed under a written binding contract, an applicant 

may treat physical work of a significant nature to have begun 

if (a) an accrual basis applicant incurs under Section 461(h) 

of the Code or (b) a cash basis applicant pays more than 

5 percent of the total cost of the property (excluding preliminary 

activities). 

In the case of multiple units of property that are located at 

the same site and will be operated as part of a larger unit 

(such as series of solar panels that are able to be operated 

independently, but will be placed in service in a series as 

part of a single project), the owner may elect to treat all the 

units (except units placed in service prior to January 1, 2009) 

as a single unit of property for purposes of determining when 

construction commences and the date the property is placed 

in service. If an applicant makes this election, the total cost 

of the project is taken into account for purposes of the safe 

harbor described above, and the failure to place the entire 

project into service will not preclude the receipt of a cash 

payment. However, only the units that are placed in service 

prior to the applicable deadline will be eligible for a cash 

payment. 

Original Use; Leases. The guidance provides that the 

original use of the property must begin with the applicant. 

However, the sale-leaseback rules are applicable and if 

property is placed in service by a person, sold to an applicant 

and then leased back by the applicant to the person 

who placed the property in service within three months of 

the placed-in-service date, the original use begins with the 

applicant/lessor and the property is considered to be placed 

in service when it is first used under the leaseback. 

In a sale-leaseback, the lessee may receive the cash payment 

if the following three conditions are satisfied: (1) the 

lessee must be the person who originally placed the property 

in service; (2) the property must be sold by and leased back 

to the lessee within three months of the placed-in-service 

date; and (3) the lessee and lessor must not make an election 

out of the sale-leaseback rules. 

The guidance also permits a lessor (who is eligible to receive 

a Treasury Grant) to pass through the cash payment to a 

lessee (who is also eligible to receive a Treasury Grant). In 

order to make the election, the property must be eligible to 

receive a Treasury grant if such property were owned by 

the lessee. If an election is made, the lessee will be treated 

as having acquired the property for an amount equal to the 

independently assessed fair market value of the property 

on the date the property is transferred to the lessee. The 

election will generally follow the rules in the Code and 

the Treasury regulations governing lessee pass-through 

elections. The guidance provides additional rules and 

requirements regarding the election. 

Grant-Eligible Property. Only tangible property (not including 

a building) that is an “integral” part” of the facility and for 

which depreciation (or amortization) is allowable is eligible 

property for purposes of determining the cash grant. The 

tangible property is tangible personal property and other 

tangible property as defined in Sections 1.48-1(c) and (d) of 

the Treasury regulations. 

The basis of the eligible property is determined in accordance 

with the general tax rules for determining the basis of 

property and includes all properly capitalized costs. Only the 

basis of property placed in service after 2008 is eligible for a 

cash grant. Thus, if property is placed in service in a qualified 

facility that was placed in service in an earlier year, only 

the basis of property placed in service in 2009 is eligible for a 

cash grant. Applicants must submit a detailed breakdown of 

the costs included in the basis of the property. For properties 

with a cost basis in excess of $500,000, an applicant must 

also submit an independent accountant’s certification regarding 

the accuracy of the claimed cost basis. 

Recapture. The Treasury Grant will vest ratably over a fiveyear 

period in the same manner as the investment tax credit. 

The following events will trigger recapture: (a) disposition of 

the property to a disqualified person, (b) the property ceases 

to qualify as specified energy property (i.e., use of the property 

predominantly outside of the United States, permanent 

cessation of production, etc.) and (c) certain other events 

that are specific to the type of facility at issue. A property 

may be sold to an entity other than a disqualified person 

without triggering recapture provided that (a) the property 

continues to be specified energy property and (b) the 

purchaser of the property agrees to be jointly liable with the 

applicant for any recapture. 

Required Documentation. Applicants must submit documentation 

that the property is eligible property and has been 

placed in service, including (a) final engineering design 

documents stamped by a professional engineer, (b) a commissioning 

report from the project engineer, equipment 

vendor or an independent third party that the equipment 



has been installed, tested and is ready and capable of its 

intended use and (c) an interconnection agreement for properties 

that are connected to a utility. 

Miscellaneous 

ÆÆ Applicants may request that the payment be assigned 

to a third party provided that certain requirements are 

met. 

ÆÆ The requirements of the National Environmental 

Policy Act (NEPA) and the Davis-Bacon Act do 

not apply to property for which a Treasury Grant is 

sought. 

ÆÆ Treasury Grant payments must be normalized under 

the rules of former Code Section 46(f). 

ÆÆ A Treasury Grant payment is not includible in the 

income of the applicant, but the basis of the property 

is reduced by 50 percent of the amount of the 

The requirements of the National 

Environmental Policy Act and the Davis- 

Bacon Act do not apply to property for 

which a Treasury Grant is sought. 

Treasury Grant (unless the property is the subject of a 

lessee pass-through election). 

ÆÆ The applicant is required to provide certain reports 

(including a project performance report) and 

certifications to Treasury and must maintain certain 

records as set forth in a terms and conditions 

document that the applicant must agree to and sign. 

Manufacturing Investment Tax Credit Program 

On August 13, 2009, the Internal Revenue Service (the 

“Service”) issued Notice 2009-72 (the “Notice”) establishing 

the qualifying advanced energy project program under 

Section 48C of the Internal Revenue Code (the “Code”). The 

American Recovery and Reinvestment Act of 2009 enacted 

a 30 percent investment tax credit for certain property used 

in a “qualified advanced energy project” — a project that 

re-equips, expands or establishes a manufacturing facility for 

the production of certain energy-related property. 

The tax credit is subject to a certification and allocation 

process. Thus, a taxpayer must be “awarded” an allocation 

of tax credits in order to claim the credit. The 73-page 

Notice describes in detail the application process, which is 

subject to tight deadlines — a preliminary application for the 

program was due by September 16, 2009. The Secretary of 

the Treasury (the “Secretary”) is authorized to allocate up 

to $2.3 billion in such tax credits (which represents approximately 

$7.7 billion of investment in qualified advanced 

energy projects). 

This article is only a summary of certain aspects of the 

manufacturing investment tax credit program guidance. 

Complete details regarding the application process and the 

program guidance are available at http://www.energy.gov/ 

recovery/48C.htm. 

Qualifying Advanced Energy Project and Eligible 

Property 

In order to qualify for the tax credit, the project must reequip, 

expand or establish a “manufacturing facility” for 

the production of “specified advanced energy property” or 

property that, after further manufacture, will become specified 

advanced energy property. A manufacturing facility 

is a facility that makes, or processes raw materials into, 

finished products (or accomplishes any intermediate stage 

in that process). Accordingly, the tax credit is for facilities 

that manufacture certain equipment (e.g., equipment that 

manufactures solar panels), and not for projects that use the 

equipment that is manufactured (e.g., a solar system that 

incorporates such solar panels). In addition, manufacturing 

facilities for the production of certain components of 

specified advance energy property are also qualified for the 

credit. For example, a project that manufactures wind turbine 

blades for a wind turbine is a qualifying project. Specified 

advanced energy property is: 

ÆÆ Property designed for the use in the production of 

energy from the sun, wind, geothermal deposits or 

other renewable resources; 

ÆÆ Fuel cells, microturbines or an energy storage system 

for use with electric or hybrid-electric motor vehicles; 

ÆÆ Electric grids to support the transmission of 

intermittent sources of renewable energy, including 

property for the storage of such energy; 

ÆÆ Property designed to capture and sequester carbon 

dioxide and to sequester carbon dioxide emissions; 



ÆÆ Property designed to refine and blend renewable 

fuels (but not fossil fuels) or to produce energy 

conservation technologies (including energyconserving 

lighting technologies and smart grid 

technologies); 

ÆÆ New plug-in electric drive motor vehicles as defined 

in Section 30D of the Code, qualified plug-in electric 

vehicles as defined in Section 30(d), or components 

that are designed specifically for use with such 

vehicles, including electric motors, generators and 

power control units; or 

ÆÆ Other property designed to reduce greenhouse gas 

emissions as may be determined by the Secretary 

in published guidance or in the letter notifying the 

taxpayer that the Service has accepted the taxpayer’s 

application for Section 48C certification. 

Eligible property for purposes of the tax credit is property 

(other than a building or its structural components) that is 

necessary for the production of specified advanced energy 

property listed above. The property must also be tangible 

personal property or other tangible property (not including a 

building or its structural components) that is used as an integral 

part of the qualifying advanced energy project. Finally, 

depreciation or amortization must be allowable with respect 

to the property. 

Application Process 

The Secretary of the Treasury is 

authorized to allocate up to $2.3 billion 

in such tax credits (which represents 

approximately $7.7 billion of investment 

in qualified advanced energy projects). 

In order to compete for an allocation of tax credits, a 

taxpayer must submit (a) a preliminary application and a 

final application for recommendation by the Department of 

Energy (“DOE”) and (b) an application for certification by 

the Service. Separate applications must be submitted for 

each separate qualifying advanced energy project. If an 

application for DOE recommendation does not contain all the 

information required by the Notice, the DOE may decline to 

consider the application. The information required to be contained 

in each submission is set forth in detail in the Notice 

and Appendix B to the Notice. If an application for Service 

certification does not contain all the information required by 

the Notice, the Service will not consider the application. The 

chart below contains a table of deadlines for various submissions 

and requirements to qualify for the tax credit. The 

deadline for the Project Information Memorandum already 

has passed — as of September 16, 2009, and final applications 

will be due in less than a month, October 16, 2009. 

Eligibility and Evaluation Criteria 

The Service will consider a project under the program only 

if the DOE provides a recommendation and ranking for the 

project. In turn, the DOE will recommend a project only if the 

DOE determines that the project is an advanced energy project 

that has a reasonable expectation of commercial viability 

and merits a recommendation based on the evaluation criteria 

set forth below. The criteria are equally weighted: 

ÆÆ Greatest job creation (both direct and indirect) during 

the credit period (February 17, 2009 through February 

17, 2013) 

ÆÆ Greatest net impact in avoiding or reducing air 

pollutants or anthropogenic emissions of greenhouse 

gases 

ÆÆ Greatest potential for technological innovation 

and commercial deployment, as indicated by 

(a) the production of new or significantly improved 

technologies, (b) improvements in levelized costs and 

performance and (c) manufacturing significance and 

value 

ÆÆ Shortest time from certification to completion 

The DOE will also take into account four program policy 

factors: (a) geographic diversity, (b) technology diversity, 

(c) project size diversity and (d) regional economic 

development. 

The DOE will rank only the recommended projects in 

descending order and the #1 ranked project will receive 

its full allocation of tax credits. The #2 ranked project will 

then receive an allocation of tax credits and so on until the 

$2.3 billion in tax credits is exhausted. If the $2.3 billion is 

not completely allocated in the first allocation round, another 

allocation round will be held the following year. (However, it 

is expected that all of the tax credits will be allocated in the 

first round.) The Service will determine the amount of the tax 

credits to be allocated to a project at the time the Service 



accepts the application for certification (the “Acceptance 

Date”). Accordingly, if the Service accepts the taxpayer’s 

application for certification, the acceptance letter will state 

the amount of the tax credits allocated to the project. 

Other Requirements 

If a taxpayer receives an allocation of Section 48C tax 

credits, it must meet certain other requirements in order to 

maintain its ability to claim the tax credits. First, it must enter 

into an agreement (similar to a closing agreement) with the 

Service regarding the tax credits. Second, within one year 

of the Acceptance Date, the taxpayer has to provide to the 

Service documents that establish that the taxpayer has 

(a) received all federal, state and local permits necessary to 

begin construction of the project and (b) completed all steps 

that must be accomplished during the one-year period beginning 

on the Acceptance Date if the project is to be placed 

in service within three years of the issuance of certification. 

Finally, the project must be placed in service within three 

years of the issuance of certification. 

All submissions to the DOE and the Service must be signed 

and dated by the taxpayer. The person signing for the 

taxpayer must sign under penalties of perjury and have personal 

knowledge of the facts contained in the document. 

Deadlines and Timelines 

Event 

Deadline 

Taxpayer Preliminary Application for DOE Recommendation Due Sept. 16, 2009 

Taxpayer Final Application for DOE Recommendation Due Oct. 16, 2009 

Taxpayer Application for Certification Due to the Service Dec. 16, 2009 

DOE Recommendations Provided to Service Dec. 16, 2009 

Service Accepts or Rejects the Taxpayer’s Application for Certification (Acceptance Jan. 15, 2010 

Date) 

Taxpayer Executes and Returns Agreement Mar. 15, 2010 

Service Executes and Returns Agreement Apr. 16, 2010 

Taxpayer Provides Evidence that Requirements of Certification are met 

One Year from Acceptance Date 

Service Makes a Decision regarding Certification of the Project (Issuance of 

One Year from Acceptance Date 

Certification) 

Project must be Placed in Service 

Three Years from Issuance of 

Certification 

Forfeiture of Tax Credits 

Numerous actions or inactions can result in the forfeiture or 

recapture of the Section 48C tax credits, including, but not 

limited to: 

ÆÆ Not placing the qualifying advanced energy project in 

service within three years of the date of issuance of 

the certification. Note that the Service does not have 

the discretion to extend this period; 

ÆÆ Failure to receive certification for the project as 

required in the Notice; or 

ÆÆ Plans for the project change that would have been 

relevant to the DOE in recommending or ranking 

the project or the Service in accepting the project 

application. 

Tax credits that are returned or forfeited may be reallocated 

in an additional allocation program in the future. 

Miscellaneous 

Section 48C provides an investment tax credit for certain 

types of property. Accordingly, the Notice provides that 

the investment tax credit-related rules such as the at-risk 

rules of Section 49 and the recapture and other special 

rules in Section 50 also apply to the Section 48C tax credit. 

The Notice also explains the application of the rules for 

claiming the Section 48C tax credits on qualified progress 

expenditures. 

There is no conference or appeals process available with 

respect to decisions made by the DOE and the Service 

under the program. If a taxpayer does receive an allocation 

of tax credits, the Service will disclose the name of the 

taxpayer and the amount of the tax credit allocated to the 

project. 



Ambiguities in ‘Buy American’ Rule Hamper Renewable 

Energy Projects 

I. Introduction 

In February 2009, Congress passed the American Recovery 

and Reinvestment Act (ARRA). The ARRA includes a large 

number of funding opportunities and tax incentives to support 

investment in clean energy at the local level. These 

incentives are designed to strengthen the economy and to 

promote clean and renewable energy. The ARRA contains 

significant direct spending programs, tax incentives, loan 

guarantees and bond programs to support the development 

of renewable and clean energy technologies. Among 

the more controversial portions of the ARRA are the Buy 

American provisions. Although the Obama administration 

has issued two sets of interim guidance for implementing 

the Buy American rules at the federal, state and local levels, 

many ambiguities remain that have the potential for delaying 

or scuttling renewable energy projects. This article provides 

background on the Buy American rules of the ARRA and 

discusses some of the ambiguities for renewable energy 

projects. 

II. Basics of Buy American Rules of ARRA 

Section 1605 of the ARRA requires that all of the iron and 

steel and “manufactured goods” used in ARRA-funded 

projects for construction, alteration, maintenance or repair 

of “a public building or public work” be “produced in the 

United States.” Section 1605 also specifies that the provision 

shall be “applied in a manner consistent with United States 

obligations under international agreements.” Exceptions are 

allowed where 

ÆÆ the head of the federal agency concerned determines 

adherence would be “inconsistent with the public 

interest,” 

ÆÆ the iron/steel/manufactures are not produced in the 

U.S. in sufficient and available quantities, or 

ÆÆ the inclusion of U.S. products would increase overall 

project cost by 25 percent. 

The Buy American rules of the ARRA generated a lot of 

controversy because governments around the world promised 

not to engage in protectionist measures in fighting the 

recession. To foreign suppliers and their governments, the 

new Buy American rules are very protectionist. On the other 

hand, to many U.S. companies, use of federal funds means 

that the projects should be reserved for U.S. companies. 

A. Similarity To Other Domestic Content Statutes 

The ARRA’s Buy American rules borrow provisions from two 

existing U.S. domestic content laws: the “Buy American Act” 

and the “Buy America” statute. The former applies when the 

federal government directly buys products or itself builds 

public buildings or works via a procurement covered by the 

Federal Acquisition Regulations, while the latter applies 

principally to highway- and transit-related projects. However, 

although similar, there are many aspects of the ARRA’s 

Buy American provisions that are significantly different from 

either the Buy American Act or the Buy America statute. 

B. The Obama Administration Interpretation Of The 

ARRA’s Buy American Provision 

Because the Buy American provisions of the ARRA contained 

very little guidance on how they should be applied, 

the Obama administration issued regulatory guidance. 

Unfortunately, three different sets of rules have been issued, 

depending on the type of contracting. 

ÆÆ On March 31, 2009, an interim rule amending the 

Federal Acquisition Regulation (FAR) was issued by 

the Civilian Agency and Defense Acquisition Councils 

(FAR Councils) imposing the ARRA’s Buy American 

provision on federal construction contracts funded 

with ARRA appropriations. 

ÆÆ On April 3, 2009, the Office of Management and 

Budget (OMB) issued guidance to federal agencies as 

to how the Buy American provision is to be applied to 

ARRA grants and loans to states and municipalities. 

ÆÆ Finally, the Federal Transit Administration and Federal 

Highway Administration (FTA/FHA) have determined 

to apply the ARRA Buy American provision by simply 

imposing their existing Buy American regulations to 

ARRA grants. 

Because the bulk of the renewable energy projects will be 

funded through ARRA funds for federal construction or state 

and municipal grants, this article focuses on the main provisions 

affecting renewable energy projects. 

1. Iron And Steel Products 

The U.S. steel industry was one of the major driving forces 

behind the Buy American provisions. As such, one of the 

main aspects of the Buy American provisions of the ARRA 



concerns iron and steel. For iron and steel products procured 

by federal contractors for use as construction material in covered 

projects, all manufacturing processes must take place 

in the United States (except metallurgical processes related 

to refining steel additives). 

2. Manufactured Goods 

A. FAR Rules 

Manufactured goods used as construction materials also 

must be produced in the United States. Unfortunately, 

the interim rules fail to define precisely what is required 

for manufactured construction material to be considered 

“produced” or “manufactured” in the United States. The 

standard espoused in the interim rules issued by the FAR 

Council states that a construction material will be considered 

“produced/manufactured” in the United States when 

it results from processing into a specific form and shape 

or combining of raw material into a property different from 

the individual raw materials, and that processing/combining 

occurs in the United States. Although this would appear to 

be a low standard, it has left many companies in the dark 

about whether their U.S. manufacturing activities meet this 

amorphous standard. Thus, unlike the criteria for steel in 

which all manufacturing processes must take place in the 

U.S., for manufactured goods, the use of components or 

subcomponents of foreign origin is allowed. Foreign components 

— including steel components — can be used to 

manufacture a product in the United States. However, the 

components have to be incorporated into a further manufactured 

or assembled product away from the construction site 

(otherwise, they would be considered construction materials 

themselves and not components). 

B. OMB Interim Guidance 

OMB’s definition of “manufactured” differs slightly from the 

definition in the FAR. Under OMB’s guidance, a manufactured 

good that contains materials from another country must 

be “substantially transformed in the United States into a new 

and different manufactured good distinct from the materials 

from which it was transformed.” The interim guidance 

adopts directly the “substantial transformation” test used to 

determine a product’s country of origin for trade purposes. 

This is a test that the U.S. Customs & Border Protection 

(“Customs”) has used for years to determine the country of 

origin of an imported product. The problem with this test, 

however, is that there are no clear and precise rules. 

In response to this lack of clarity, the Environmental 

Protection Agency (EPA) has provided some guidance on 

what it considers to be a substantial transformation. To help 

local utilities determine whether a good has been “substantially 

transformed” enough to pass the test, the federal 

agency provided a series of questions: 

ÆÆ Were all of the components of the manufactured 

good manufactured in the U.S., and were all of the 

components assembled into the final product in 

the U.S.? (If the answer is “yes,” then this is clearly 

manufactured in the U.S.) 

ÆÆ Was there a change in character or use of the good 

or the components in America? (These questions are 

asked about the finished good as a whole, not about 

each individual component.) 

ÆÆ Were the processes performed in the U.S. (including 

but not limited to assembly) complex and meaningful? 

According to the EPA, an imported component that undergoes 

further processing in the United States would not 

satisfy the substantial transformation test by “having merely 

undergone ‘[a] simple combining or packaging operation.’ ” 

Moreover, “assembly operations that are minimal or simple, 

as opposed to complex or meaningful, will generally not 

result in a substantial transformation.” 

Although the EPA has issued guidance on how the substantial 

transformation test works, it is uncertain whether 

the EPA’s guidance will apply to renewable energy projects, 

where most funding comes from Department of Energy 

grants. 

3. International Obligations 

Pursuant to the ARRA, the Buy American provisions must 

be applied in a manner consistent with the WTO Agreement 

on Government Procurement (GPA) and U.S. free trade 

agreements. Under these agreements, the Buy American 

requirement does not apply to iron, steel or manufactured 

goods produced in signatory countries and acquired for construction 

projects with a value of $7.4 million or more. Thus, 

procuring agencies must honor the federal government’s 

commitments to treat the foreign iron, steel or manufactured 

goods as the equivalent of domestic goods. In determining 

whether a product is a product of the GPA or free trade 

agreement country, the rules specify that the “substantial 

transformation” test is to be used to determine country of origin 

when a manufactured good that contains materials from 

another country is processed in the GPA or FTA country. 



Note that this exception to the Buy American provision of 

the ARRA does not always apply. Although the exception 

applies to federal government procurements for construction 

projects, it only applies to states and municipalities who have 

signed on with respect to their agencies. Although 32 states 

have signed on to the GPA, the fact is that very few state 

or local agencies are covered. Because most of the ARRA 

funds are disbursed through grants to states and municipalities, 

there is a significant likelihood that the Buy American 

provisions will apply to any state or local projects that use 

ARRA funds. 

4. Violations of the Buy American Provisions 

Both the FAR and OMB interim rules include provisions for 

dealing with violations of the Buy American rules. A violation 

could result in contract termination for default, reduction in 

the contract price, suspension and debarment of the contractor 

and, potentially, even criminal liability. Moreover, because 

each contractor must submit a certificate of compliance with 

the Buy American rules, a violation of the Buy American 

provisions could result in False Claims Act liability. 

III. Specific Issues for Renewable Energy Project 

A. When Do The Buy American Rules Of The ARRA 

Apply? 

There are several contexts where it is uncertain whether the 

Buy American rules of the ARRA apply. 

1. Grants In Lieu Of Tax Credits 

Section 1603 of the ARRA allows taxpayers to claim, in lieu 

of claiming the investment tax credit or production tax credit, 

a grant when they place “specified energy property” in service. 

The grant reimburses the taxpayer for a portion of the 

expense of such property. 

The Buy American provision applies to projects receiving 

“funds appropriated or otherwise made available by this Act.” 

The law is divided into an introductory section, a Division A 

and a Division B. Section 4 of the introductory section states 

that references to “this Act” contained in any division of the 

legislation are to be treated as references only to the provisions 

of that division. The Buy American provisions appear in 

Division A, while the tax provisions, including grants in lieu of 

tax credits, are in Division B. Thus, the Buy American provisions 

should not apply to the tax provisions, including grants 

in lieu of tax credits. 

Unfortunately, however, no mention was made of this in 

either the interim guidance or rules. Nevertheless, a treasury 

official has stated that the grants in lieu of tax credits do 

not have to comply with the Buy American provisions of the 

ARRA. However, nothing official has been issued concerning 

whether the Buy American rules of the ARRA apply to grants 

in lieu of tax credits. 

2. Loan Guarantees 

[B]y definition the Buy American 

provisions of ARRA should not apply to 

loan guarantees for private projects. 

On July 29, 2009, the Department of Energy issued $30 billion 

in lending authority to support loan guarantees for 

renewable energy and transmission projects. Unlike the tax 

provisions, loan guarantees are in Division A of the ARRA. 

As such, recipients of ARRA funds conceptually must comply 

with the Buy American provisions. Nevertheless, many of 

the projects receiving funds are private projects, typically 

through a Power Purchase Agreement (PPA). Under the 

terms of a PPA, the PPA provider (the electricity generator) 

typically assumes the risks and responsibilities of ownership 

when it purchases, operates and maintains the facility. 

Because the Buy American provisions only apply to ARRA 

funds given for construction, repair, alteration and so on 

of a public works or public building, by definition the Buy 

American provisions of ARRA should not apply to loan guarantees 

for private projects. 

Although the Buy American provisions should not apply to 

these types of private projects, the interim guidance has not 

addressed this issue squarely when it comes to renewable 

energy projects. Moreover, there are a host of issues that 

could make a difference when it comes to PPAs. Would it 

make a difference if the host site operator itself is a governmental 

entity? Does it make a difference if the host site 

operator is a governmental entity that has an option to buy 

the facility? These are just some of the issues that were not 

addressed in the interim guidance. 



3. Substantial Transformation Test 

As stated above, there are two amorphous standards that 

are espoused for determining when products that undergo 

further manufacturing can be considered a product of 

the United States (or a product of a free trade agreement 

country). Despite guidance by the EPA, the fact is that these 

standards are not predictable. Without predictability, it makes 

it extremely difficult for renewable energy companies to know 

whether their projects are compliant with the Buy American 

rules. 

Even Customs has proposed eliminating altogether the 

substantial transformation test due to its unpredictability. 

Customs has stated the following: 

Despite its heritage and apparent straightforwardness, 

administration of the substantial transformation 

standard has not been without problems. These 

problems derive in large part from the inherently 

subjective nature of judgments made in case-by-case 

adjudications as to what constitutes a new and different 

article and whether processing has resulted 

in a new name, character, and use. The substantial 

transformation standard has evolved over many 

years through numerous court decisions and CBP 

administrative rulings. Because the rule has been 

applied on a case-by-case basis to a wide range of 

scenarios and has frequently involved consideration 

of multiple criteria, the substantial transformation 

standard has been difficult for the courts and CBP to 

apply consistently and has often resulted in a lack of 

predictability and certainty for both CBP and the trade 

community. 

Instead, Customs has proposed a change in tariff classification 

system (tariff shifts) for determining whether a change 

in origin has occurred. Under this codified method, the substantial 

transformation that an imported good must undergo 

in order to be deemed a good of the country where the 

change occurred is usually expressed in terms of a specified 

tariff shift as a result of further processing. This system currently 

is in place for making origin determinations for goods 

imported from Canada and Mexico pursuant to the North 

American Free Trade Agreement. 

Due to its predictability, in any final guidance, the FAR 

Council and OMB should adopt the change in tariff 

classification system for determining origin for Buy American 

purposes. 

4. Guidance 

Another issue for the renewable energy industry is the lack 

of transparency with regard to procedures for having Buy 

American coverage issues resolved. Although OMB and 

the FAR Council issued the guidance on the Buy American 

provisions, given the overarching issues, there is no central 

authority to uniformly decide Buy American issues. Rather, 

typically it is the contracting officer that in the first place 

makes decisions concerning the Buy American provisions. 

The problem with this type of system is that many decisions 

are made without significant oversight and uniformity. There 

should be transparent and uniform rules concerning issues 

involving the Buy American rules that are issued by a lead 

agency like OMB. Unfortunately, however, no such hierarchy 

exists. This further stymies businesses because of the lack 

of predictability. 

IV. Conclusion 

Given the ambiguities in the guidance and rules, coupled 

with the significant potential penalties for non-compliance, it 

is critical that renewable energy companies be aware of how 

the Buy American provisions apply and seek legal counsel to 

address those areas that it believes are unclear. 

Addendum 

In early summer, both the FAR Council and the OMB 

accepted comments on their interim guidance and rules. 

Many comments were received. Both the FAR Council and 

OMB intend to issue final rules in early fall. As of the submission 

of this article, the final guidance rules have not yet been 

released. 



Green Investment Funds: Threshold Considerations and Challenges 

With the Obama administration’s focus on renewable energy 

and the implementation of the American Recovery and 

Reinvestment Act of 2009 (“ARRA”), we are seeing increasing 

investment interest in the renewable energy sector. 

Existing private investment funds with a generalist mandate 

are increasingly looking to deploy capital in the renewable 

energy industry. In addition, investment bankers and energy 

industry experts are increasingly looking to raise private 

investment funds devoted to renewable energy investing. 

Whether raising a new fund, or investing from an existing 

fund, there are some basic, threshold considerations and 

challenges the investment team should take into account. 

Those considerations and challenges are introduced below. 

This article is not intended to deter investors from this class 

of investment, but merely to inform on the threshold issues 

investors should consider and plan around before diving in. 

When talking about renewable energy investment funds, we 

tend to think of funds in several discrete categories, based 

on the way the fund needs to be, or is typically, structured in 

relation to its investment thesis, including: 

Æ Æ Clean Tech Funds. Clean Tech Funds seek 

investments in “green” or other energy-related 

technologies. These funds tend to follow a structure 

and investment program similar to traditional, 

technology-focused, venture capital funds. 

Æ Æ Energy Services Funds. Energy Services Funds 

make investments in operating businesses that derive 

revenue from the energy industry — development 

firms, engineering firms, manufacturers and 

similar businesses. These funds typically employ a 

traditional, generalist private equity or buyout fund 

model. 

Æ Æ Project Funds. Project Funds seek investments in 

renewable energy projects and installations. These 

funds can focus on the early, development stage of 

the project or a later, mature stage of projects that 

generate cash flow. The projects typically sought 

include wind, solar, geothermal, biomass and other 

renewable resources, and, as a result, may be eligible 

for federal tax credits, accelerated depreciation, 

newly implemented federal grants and other federal 

and state incentives. Traditionally, these funds were 

often structured like tax credit funds and catered to 

tax-driven investors. Today, the structure and role of 

these funds is in flux in light of the implementation 

of ARRA and investment trends. These funds often 

involve more complicated, tax-driven structures and 

terms, and confront legal and tax issues not typically 

confronted by other types of funds. This article 

focuses mainly on these types of funds. 

Impending Regulatory Reform 

Existing fund managers, and especially those considering 

launching a new fund, should be aware of the pending 

regulatory reform that is likely to increase regulation and 

compliance burdens of private equity fund managers. While 

none of the reforms are final, many who follow these matters 

expect that some form of the current proposals discussed 

below will likely become reality. 

Existing fund managers, and especially 

those considering launching a new 

fund, should be aware of the pending 

regulatory reform that is likely to increase 

regulation and compliance burdens 

of private equity fund managers. 

The single biggest pending change is the requirement for 

almost all fund managers to register as investment advisers. 

A number of proposals have circulated in the past year that 

would require managers of private investment funds to register 

as investment advisers under the Investment Advisers 

Act of 1940 (the “Advisers Act”). The most recent proposal, 

the “Private Fund Investment Advisers Registration Act of 

2009,” proposed by the Obama administration on July 10, 

2009, would eliminate the private adviser exemption found 

in Section 203(b)(3) of the Advisers Act (also known as the 

“15 client” exemption). Many investment advisers to private 

funds rely on the private adviser exemption as well as the 

client counting rules found in Rule 203(b)(3)-1 to avoid registration 

under the Advisers Act. The elimination of the private 

adviser exemption would require all investment advisers with 

$30 million or more in assets under management to register 

with the SEC. Although general partners and managers to 



private funds are already subject to the antifraud rules of 

the Advisers Act, if they are required to register as investment 

advisers, they will become subject to all provisions of 

the Advisers Act, including its rules relating to client asset 

custody, recordkeeping, advisory contracts, limitations on 

performance fees, ethics and personal trading policies, 

investment and financial reporting, and advertising. 

In addition to the regulation of fund managers under the 

Advisers Act, another recent proposal would subject private 

investment funds to additional regulation as “investment 

companies” under the Investment Company Act of 1940 

(the “Investment Company Act”). Also under this proposal, 

“large investment companies” (those with assets under 

management of $50 million or more) would be required to 

register with the SEC under the Investment Company Act 

and comply with other disclosure, reporting and examination 

requirements. 

Another proposal, the “Corporate and Financial Institution 

Compensation Fairness Act of 2009” (H.R. 3269), which was 

passed by the House of Representatives on July 31, 2009, 

includes a requirement that the SEC and other federal regulators 

adopt rules requiring investment advisers and other 

covered financial institutions with assets of at least $1 billion 

to disclose incentive-based compensation arrangements and 

prohibiting certain incentive-based payment arrangements. 

As of this writing, there is little information regarding the 

disclosure rules and types of incentive-based compensation 

practices that would be prohibited by investment advisers, 

such as fund sponsors. The Senate has not approved 

comparable legislation and the prospects for the bill being 

enacted into law are uncertain as of this writing. 

In addition, the SEC has proposed for comment rules placing 

restrictions on political contributions and the use of placement 

agents in connection with soliciting investments from 

governmental plans. These restrictions may make it harder 

for first-time fundraisers, but would only impact marketing 

to public pensions. For the reasons discussed below, these 

public pensions may be less likely candidates for investment 

in Project Funds. 

Changing Tax Rates 

Once again, Congress is attempting to increase taxes on 

the lucrative incentive compensation that private equity fund 

managers receive from the funds they manage. Currently, 

the character of income received from a partnership such as 

a private equity fund is determined at the partnership level, 

so that partners report ordinary income, capital gain and/or 

qualified dividend income depending on the character of the 

income received by the partnership. Thus, if the partnership 

recognizes long-term capital gains and qualified dividends, 

the individual partners would be subject to tax on that 

income at capital gains rates. Recently, the U.S. Treasury 

Department (“Treasury”) proposed to tax income and gain 

from a partnership profits interest received in exchange for 

services (known as “carried interest”) as ordinary income 

regardless of the character at the partnership level, unless 

the income or gain was attributable to the partner’s “invested 

capital.” The income from a carried interest would also be 

subject to self-employment taxes. The carried interest proposal 

would apply to all partnerships and would be effective 

for taxable years beginning after December 31, 2010. In 

addition, the proposal would eliminate the current 33 percent 

and 35 percent tax brackets and would add tax rate 

brackets of 36 percent and 39.6 percent for individuals with 

income over $250,000 (or $200,000 for single taxpayers). 

The proposal would increase the tax rate on capital gains 

and dividends to 20 percent for individuals with income over 

$250,000 (or $200,000 for single taxpayers), effective for 

taxable years beginning after December 31, 2010. Due to 

the number of recent proposals to modify the tax treatment 

of carried interest and the lack of any apparent significant 

political opposition to such a proposal, it seems likely that 

some form of the current proposals to tax carried interest at 

ordinary income rates will be approved in the near future. 

Potential Investors 

Sponsors considering investment of existing funds in renewable 

energy projects, and those raising new Project Funds, 

should focus on whether their current or anticipated investor 

base can benefit from relevant government programs, the 

incentives from which often make the difference between 

viable and nonviable projects. Project Funds and renewable 

project investments were traditionally sought mostly 

by tax equity investors. The Project Fund could allocate 

the federal tax credits and accelerated depreciation to the 

taxable investors seeking an after-tax return. However, in 

mid to late 2008, the traditional tax equity investors found 

themselves without a tax reduction appetite and equity 

investment in these projects stalled. The Obama administration 

and Congress offered some help in the form of the 

ARRA. The ARRA permits taxpayers to claim cash grants in 

lieu of production or investment tax credits for certain types 

of renewable energy facilities, such as wind, closed-loop 

biomass, open-loop biomass, geothermal, solar, landfill gas, 



waste-to-energy, hydropower or marine/hydrokinetic facilities, 

placed in service in certain specified time periods. The 

cash grant program seems to have become an attractive 

alternative to the federal tax benefits. In addition, there is 

no limit on the amount of grants available through the grant 

program, making it an attractive alternative for funds that 

have not yet developed or placed facilities in service but 

plan to place such facilities in service within the relevant time 

periods. 

Tax-Exempt Investors 

Notwithstanding this broadening of benefits for renewable 

project investing, a major source of capital for private equity 

funds — tax-exempt investors, such as governmental plans, 

private pension plans, endowments, foundations and the 

like — are largely unable to participate. Although the grant 

program essentially converts tax credits to cash, many of 

the investor eligibility and fund structuring concerns for a tax 

credit fund will still apply. In particular, the Treasury guidance 

for the grant program provides that each direct and indirect 

investor in a partnership (such as a private investment fund) 

must be eligible to receive grant payments in order for the 

partnership to be eligible to receive grant payments. Many 

types of tax-exempt investors are not eligible to receive grant 

payments. Although the Treasury guidance further provides 

that the Treasury guidance expressly permits a partnership 

to establish a “blocker” or taxable C corporation through 

which these ineligible investors may invest, the tax impact 

associated with a blocker often decreases after-tax returns 

below a viable threshold. 

High-Net-Worth Individuals 

In addition, high-net-worth individuals also generally cannot 

participate in these federal renewable energy investment 

benefits. Noncorporate investors (and certain closely held, 

personal service and S corporations) are subject to the 

limitations on using losses and credits from passive business 

activities to offset certain types of income such as interest, 

dividends and capital gains from portfolio investments. There 

are also certain limitations on the amounts of partnership 

items that can be deducted by noncorporate taxpayers and 

closely held corporations. A private equity fund’s income or 

losses generally will be treated as passive activity income 

or losses. However, passive activity losses from renewable 

energy investments can be used to offset passive income 

from other sources, such as rental income, so high-net-worth 

individuals who have substantial qualifying passive income 

may still find such a fund attractive. Accordingly, individuals 

and closely held corporations or other entities subject to the 

passive activity rules should reasonably expect to have sufficient 

unsheltered passive income from other sources to use 

the tax losses and credits anticipated from an investment in 

the fund. Losses and credits that are currently disallowed 

under the passive limitations are suspended and may be 

carried forward to subsequent taxable years. If an investor 

subject to the passive activity rules does not have sufficient 

unsheltered passive income from other sources, the full 

extent of the tax benefit of the investment will not be realized 

by the investor. As a result, such investors may find such a 

fund to be a less attractive investment. 

Offshore Investors 

Offshore investors are also a source of significant capital 

for traditional private equity funds, but may not be good 

candidates for a Project Fund. As discussed above, the tax 

Because of these difficulties in providing 

maximum benefits (and therefore returns) 

to some of the traditional sources of 

private equity capital — tax exempts, 

high-net-worth individuals and offshore 

investors — sponsors of a new Project 

Fund should carefully consider its target 

investor base before launching the fund. 

credits, grants and related incentives often make viable a 

project that might not otherwise be viable. If the offshore 

investor is not a U.S. taxpayer, these benefits will not 

enhance its return. Moreover, a foreign person or entity may 

be eligible for a grant payment only if at least 50 percent of 

the income of the person or entity is subject to U.S. income 

tax, so the participation of ineligible offshore investors may 

disqualify the fund from participation in the grant program. 

Recapture Risk 

Each Treasury grant will vest ratably over a five-year period 

(similar to an investment tax credit) and must be repaid 

to the Treasury if certain events occur. These recapture 

events include: (1) the sale of any interest in the property, 



the owner or the partnership that is a direct or indirect 

owner to a disqualified person; (2) the property ceasing to 

qualify as specified energy property; and (3) other specified 

events applicable to particular types of renewable energy. 

A property may be sold to an entity other than a disqualified 

person without triggering recapture, so long as the 

property continues to be specified energy property, and the 

purchaser of the property agrees to be jointly liable for any 

recapture. Private investment fund sponsors should consider 

addressing potential recapture issues in fund partnership 

agreement provisions prohibiting transfers and assignments 

of fund interests to disqualified persons, investment 

guidelines prohibiting dispositions of projects to disqualified 

persons, distribution clawbacks requiring partners to return 

distributions associated with the recaptured amounts, and 

provisions establishing specific reserves. 

Because of these difficulties in providing maximum benefits 

(and therefore returns) to some of the traditional sources of 

private equity capital — tax exempts, high-net-worth individuals 

and offshore investors — sponsors of a new Project 

Fund should carefully consider its target investor base 

before launching the fund. Before embarking on a renewable 

energy project investment or strategy, an existing fund 

should consider its investors and any provisions in its partnership 

agreement or other fund documents that allow it to 

consummate investments while excluding certain investors. 

Timing 

The Treasury began accepting applications for the grant 

program on July 31, 2009, and awarded approximately 

$500 million of grants in the first round of awards in early 

September 2009. For property placed in service in 2009 or 

2010, an application cannot be submitted for a project until 

after the project is placed in service, and must be submitted 

before October 1, 2011. For projects that are under 

construction in 2009 or 2010, but not placed in service until 

after 2010, applications must be submitted after construction 

has begun, and before October 1, 2011. As a result of these 

timing issues, fund managers may have a limited window in 

which to deploy capital under these beneficial programs, so 

will need a plan to raise and invest this capital on a diligent 

basis. 

Conclusion 

Existing and new private investment fund sponsors confront 

several threshold considerations in determining whether 

renewable energy investing is right for them. Fund managers 

generally are likely to come under increasing regulation 

and scrutiny, and it is likely that taxes on traditional forms of 

private equity compensation will increase. Federal and state 

governments have traditionally provided incentives to investors 

in renewable energy projects, and those incentives have 

recently been expanded. However, fund sponsors should 

consider whether these benefits can be adequately transferred 

to their anticipated investor base, as several traditional 

sources of private equity capital may have problems realizing 

these benefits or require special structuring in order to do so. 

There are strategies to deal with many of these issues, but 

they should all be confronted early in the planning process 

so all parties have realistic and achievable expectations. 



Industry Happenings 

Sahara Sun to Power Europe? 

As solar projects continue to surge, the horizons for development 

have expanded to less likely places, such as Tunisia. 

A German consortium is now building support for one of the 

world’s most ambitious solar power projects to date. The 

$573 billion endeavor, known as Desertec, would harness 

solar energy from fields of mirrors in the Sahara and convey 

power to a carbon-free network linking Europe, the Middle 

East and North Africa. 

Munich Re, a German insurance company, is the driving 

force behind this major undertaking and has expressed 

interest in playing a role as an investor and insurer once the 

project gets off the ground. The technology envisioned would 

collect solar rays to produce steam for turbines that produce 

electricity, which would be transmitted through high-voltage 

direct current (HVDC) cables. 

Opponents of the initiative argue that the economic and 

political risks are too great. In addition to the instability of the 

region, the project would require 20 or more cables, each 

costing up to $1 billion, to transmit electricity north beneath 

the Mediterranean. Supporters counter that the project could 

one day provide 15 percent of the energy used by Europe. 

Desertec could also empower countries like Morocco to 

export energy instead of importing. 

The experts have yet to draft a business plan or determine 

financing of the project. The next step in Desertec will be to 

legally incorporate, which is planned for October 31. 

Hydropower Gains Momentum with Boost from DOE 

At the end of June, U.S. Department of Energy Secretary 

Steven Chu announced up to $32 million in Recovery Act 

funding specifically for modernizing the hydropower infrastructure, 

increasing efficiency and reducing environmental 

impact. In July, DOE announced its plans to provide up to 

$30 billion in loan guarantees to companies investing in 

new renewable energy projects, including hydropower. The 

additional incentive of investment tax credits or grants has 

further insured a swell of hydropower improvement and 

advancement. 

Hydropower is the nation’s biggest source of renewable 

energy and the DOE is committed to improving the technology. 

A major advantage to hydropower is the ability to store 

and release the energy on demand. On September 15, the 

DOE announced that 22 advanced waterpower projects 

will receive up to $14.6 million in funding, which includes 

conventional hydropower plants. Secretary Chu remarked 

that “these projects will provide critical support for the development 

of innovative renewable waterpower technologies 

and help ensure a vibrant hydropower industry for years to 

come.” 

Queens Tests Con Edison’s Smart Grid Program 

On August 4 Consolidated Edison Company of New York, 

Inc., announced that Queens will be home to a $6 million 

smart grid pilot program. The program features sophisticated 

technology designed to improve the delivery of electricity to 

the residents and the utility’s ability to respond to customer 

use and power interruptions. Approximately 1,500 customers 

will participate in the project, which will run for a period of 



18 months. Another 300 residents will have home meters 

that will gauge their consumption so they will have the option 

to manage their energy usage and thereby save money. 

The City University of New York will also participate in the 

pilot by testing the integration of solar energy into the city 

grid. The energy will be collected from a 100kW photovoltaic 

system on the roof of LaGuardia Community College. 

If the pilot proves a success, Con Ed hopes to bring the 

advances to the rest of the city. Since the announcement 

of the Queens project, Con Ed has applied for a total of 

$188 million in federal stimulus funds to support their overall 

$435 million smart grid program. 

Farmers Cut Costs and Emissions with Legislation 

Pending 

Climate change legislation has been the source of much 

debate in the agricultural community, but farmers have been 

making positive changes while lawmakers work out the 

details. Over the last few years, an increasing number of 

dairy farmers in Wisconsin have successfully lowered their 

operational costs with the use of biogas digester systems. 

The biogas engines generate enough power for on-site electricity 

needs and the excess power can often be sold back to 

the regional grid. 

In January a bipartisan group of U.S. senators introduced 

legislation to encourage the development of biogas, the 

Biogas Production Incentive Act of 2009. If passed, the bill 

would encourage greater production of biogas for energy 

purposes by providing biogas producers with a tax credit 

of $4.27 for every million British thermal units of biogas 

produced. According to the U.S. Department of Energy, if the 

U.S. used half of its waste biomass, biogas could replace 

about 5 percent of the natural gas currently being used, 

reducing carbon dioxide emissions by another 45–70 million 

metric tons per year. 

U.S. Military and Investors Help Algae Research Grow 

On September 8 Solazyme Inc., a synthetic biology company 

specializing in algal biodiesel, announced that it had signed 

a contract with the Defense Department to develop 20,000 

gallons of algae-derived diesel fuel for testing. This contract 

is a symbolic leap forward for the advanced research and 

development of large-scale advanced biofuel production 

from algae. Earlier this year, the Defense Advanced 

Research Projects Agency (DARPA) awarded a $25 million 

contract to Science Applications International Corp. for the 

development of an algae-based jet fuel for the U.S. military. 

The military’s ultimate goal of energy independence continues 

to act as a catalyst for alternative energy pioneers like 

Solazyme. 

Algae are among the fastest-growing plants in the world. 

Approximately 50 percent of their weight is lipid oil, which 

can be used to make biodiesel for cars, trucks and airplanes. 

Many others are investing in the promise of algae. In July 

ExxonMobil and startup Synthetic Genomics announced 

more than $600 million for a five- to six-year algae biofuels 

development program, including more than $300 million to 

be invested into the startup. Bill Gates’ Cascade Investment 

has funded Sapphire Energy’s development of auto fuel from 

algae. In early September, Sapphire Energy’s green crude 

powered the world’s first algae-fueled vehicle — a modified 

Toyota Prius also know as Algaeus. Although it is premature 

to say we will conquer our dependence on foreign oil with 

algae, recent developments demonstrate it is a fuel with 

great potential. 



Letter From the Editor 

Dear Readers, 

This September 2009 issue marks the first anniversary of the 

Renewable Energy Quarterly. Hunton and Williams is proud 

to be one of the only law firms in the country that offers 

a quarterly publication devoted exclusively to renewable 

energy. Our authors strive to shed light on the leading legal 

issues affecting industry participants and contribute to the 

renewable industry dialogue as a whole. Our publications 

cover a wide range of subject matters, including current 

legislation, federal and state policy initiatives and issues 

affecting the investment community. 

When the first edition was published in September of 2008, 

our country, along with the rest of the world, had just entered 

one of its most difficult economic cycles and uncertain times 

for the global power market. In spite of this setback, key 

players in this sector have stayed the course and forged 

ahead, bolstered in part by the creative energy and innovative 

strategies of industry participants as well as support from 

federal and state policy makers and industry associations. 

As a firm, Hunton and Williams is dedicated to the growth 

and success of sustainable energy solutions. We are committed 

to the ambitions of our clients to improve the global 

environment and will continue to support them in their mission 

to mitigate the financial, physical and health burdens on 

future generations. 

Sincerely, 

Thomas B.Trimble 

Hunton In The News 

Hunton & Williams Hosts Series of Homeland Security 

Policy Breakfasts 

In June, Hunton & Williams kicked off a series of Homeland 

Security Policy Breakfasts featuring a variety of topics. The 

most recent event took place in our D.C. office and focused 

on “The Smart Grid: Meeting the Challenge of Modernizing 

Electric Systems While Protecting Their Security.” 

Each event includes a panel of experts in the industry and 

concludes with a Q&A session. The next event is scheduled 

for September 24, 2009, and will cover “Cloud Computing: 

Are the Security Risks Real or Exaggerated?” 

Hunton & Williams Pro Bono Leader George Hettrick 

Named American Lawyer Lifetime Achiever 

Hunton & Williams is pleased to announce The American 

Lawyer® named George H. Hettrick, firm partner and chair 

of the firm’s Community Service Committee, a 2009 Lifetime 

Achiever. The annual award recognizes lawyers who have 

made significant contributions to public service while also 

building an outstanding legal practice. Following a 25-year 

career as a corporate finance lawyer, Hettrick took on 

the challenge of leading the firm’s pro bono practice on a 

full-time basis. Nearly 100 percent of our U.S. lawyers participated 

in our pro bono program last year, donating nearly 

73,000 hours. 

H&W Shortlisted in Corporate Counsel’s Annual Who 

Represents Whom 

Hunton & Williams was listed among the top ten most-used 

outside counsel by Fortune 100® companies in Corporate 

Counsel’s 2009 “Who Represents Whom.” The magazine 

annually researches the nation’s largest companies to identify 

their “go-to” firms in each of the following practice areas: 

commercial law and contracts litigation; corporate transactions; 

employment and labor litigation; intellectual property 

litigation and patent prosecution; and torts and negligence. 

Robert Grey Nominated to Legal Services Corporation 

and Appointed Interim Director of Leadership Council on 

Legal Diversity 

Hunton & Williams partner Robert Grey was recently nominated 

to the Legal Services Corporation (LSC) by President 

Barack Obama. Once appointed to the LSC board, Grey will 

serve alongside 10 directors to set policy for the country’s 

single-largest provider of civil legal aid to the underprivileged. 

Grey was also recently appointed interim executive 

director of the Leadership Council on Legal Diversity. A 

newly formed organization of chief legal officers and law 

firm managing partners, the council is dedicated to creating 

a truly diverse legal profession. Grey’s responsibilities will 

include increasing the council’s membership, establishing 

partnerships to advance its mission, creating best practices 

for the promotion of diversity in the legal profession and 

helping identify a permanent executive director. 



Hunton & Williams Renewable Energy Quarterly 

Issue 5, September 2009 

Editor 

Thomas B. Trimble 

Advisory Board 

Fernando C. Alonso 

P. Scott Burton 

John Deacon 

Laura E. Jones 

Ted J. Murphy 

Enid L. Veron 

Contributors 

William L. Wehrum and Scott J. Stone 

Federal Climate Legislation: The End Would Be Just The 

Beginning 

Edward B. Koehler, Chumbhot Plangtrakul and Peter Francis 

Schultz 

Progress To Date in Implementing China’s Renewable 

Energy Law of 2006 

Edward B. Koehler, Weiqi Fei and Peter Francis Schultz 

Renewable Energy Development Prospects of Southeast 

Asia’s ‘Green Tigers’ 

Laura E. Jones and Timothy L. Jacobs 

Recovery Act Guidance Update 

Douglas J. Heffner 

Ambiguities in ‘Buy American’ Rule Hamper Renewable 

Energy Projects 

Cyane B. Crump and James S. Seevers, Jr. 

Green Investment Funds: Threshold Considerations and 

Challenges 

Hunton & Williams LLP 

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© 2009 Hunton & Williams LLP. Attorney advertising materials. These materials have been prepared for informational purposes 

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us confidential information. Past successes cannot be an assurance of future success. Whether you need legal services and which 

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Hunton & Williams Renewable Energy Quarterly, September 2009

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