APPA's Competitive Market Plan - American Public Power Association
APPA's Competitive Market Plan - American Public Power Association
APPA's Competitive Market Plan - American Public Power Association
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2011 Update<br />
APPA’s<br />
<strong>Competitive</strong><br />
<strong>Market</strong> <strong>Plan</strong>:<br />
A Roadmap for Reforming Wholesale Electricity <strong>Market</strong>s<br />
R
APPA’s<br />
<strong>Competitive</strong><br />
<strong>Market</strong> <strong>Plan</strong><br />
Update 2011<br />
A Roadmap for Reforming Wholesale Electricity <strong>Market</strong>s<br />
June 2011<br />
Copyright 2011 by the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong>. All rights reserved.<br />
Published by the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong>, 1875 Connecticut Ave., NW, Suite 1200,<br />
Washington, DC 20009-5715 • www.<strong>Public</strong><strong>Power</strong>.org
Acknowledgements<br />
APPA would like to acknowledge the many individuals who provided valuable writing<br />
assistance, suggestions, comments and feedback, including Kenneth Rose,<br />
Ph. D., Independent Consultant; Gary J. Newell, Thompson Coburn, LLP; James<br />
A. Jablonski, Executive Director, <strong>Public</strong> <strong>Power</strong> <strong>Association</strong> of New Jersey; Robert<br />
McCullough, McCullough Research; Paul Williams, Pennsylvania Steel & Cement<br />
Manufacturers Coalition and Howard Spinner, Virginia State Corporation Commission.<br />
The views expressed in this paper are those of APPA alone and should not<br />
be attributed to any individual who kindly assisted us in this effort.
Table of Contents<br />
Executive Summary................................................................xii<br />
I. Introduction ............................................................................1<br />
II. Background.............................................................................7<br />
III. Overview of Proposed <strong>Market</strong> Structure ................................12<br />
IV. Role of State Regulatory Agencies.........................................15<br />
V. Bilateral Contracts .................................................................21<br />
VI. <strong>Market</strong> <strong>Power</strong> .......................................................................27<br />
VII. Residual Short-Term and Imbalance Services:<br />
The Optimization <strong>Market</strong>........................................................30<br />
VIII. RTO Operations to Support Non-Discriminatory<br />
Transmission Access .............................................................34<br />
IX. Renewable Energy.................................................................38<br />
X. Resource Adequacy and <strong>Plan</strong>ning .........................................42<br />
XI. Transmission <strong>Plan</strong>ning ...........................................................47<br />
XII. Transition Issues ....................................................................49<br />
XIII. Conclusion ............................................................................50<br />
Appendix A: Division of Responsibilities for<br />
Resource Adequacy in Current RTO <strong>Market</strong> Structures ..................52<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update iii
Preface to the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update<br />
I<br />
n February 2009, the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong> (“APPA”)<br />
released a proposal to reform the centralized markets run by<br />
Regional Transmission Organizations (“RTOs”), which it called the<br />
“<strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>” (“CMP”). In doing so, APPA hoped to “jumpstart”<br />
a dialogue among industry participants to develop much needed<br />
reforms to RTO-run markets. As APPA noted at the close of its proposal<br />
(CMP at 39):<br />
The debate should no longer be about who can best massage the<br />
statistics or whether it is more virtuous to support “competition” or<br />
“regulation.” Instead, the industry must work together to develop a<br />
regulatory regime for electricity markets in RTO regions that will<br />
truly benefit consumers, businesses and the environment. Unless<br />
the electric utility industry and its regulators can agree on a market<br />
design and regulatory paradigm that fairly balances the interests of<br />
both load and generation, the industry will be condemned to<br />
continued upheaval.<br />
Unfortunately, the release of APPA’s CMP did not have the effect that APPA<br />
had hoped. There was plenty of public reaction by incumbent generation<br />
owners to the plan, but it consisted primarily of mischaracterization and<br />
resultant dismissal of APPA’s proposal, 1 and claims that APPA in fact wanted to<br />
return to cost-of-service ratemaking or institute a “pay-as-bid” auction regime. 2<br />
Those asset owners with financial interests in maintaining the current RTO<br />
market structure (including locational capacity markets) expended their<br />
energies on a public relations effort to discredit the CMP and APPA, rather<br />
than to use the CMP’s issuance as an opportunity to engage in an actual<br />
debate about possible RTO market reforms 3 .<br />
The result has been the “continued upheaval” that APPA feared. Litigation<br />
at the Federal Energy Regulatory Commission (“FERC” or “Commission”) and<br />
in the appellate courts regarding RTO market features continues apace, as<br />
generator and load interests attempt to craft specific market rules and<br />
procedures that work best for their respective interests. This new version of<br />
the CMP updates APPA’s 2009 proposals and concerns to address several<br />
1<br />
See, e.g., John D. Chandley and William W. Hogan, Electricity <strong>Market</strong> Reform: APPA’s Journey<br />
Down The Wrong Path, LECG, prepared for the COMPETE Coalition, April 16, 2009,<br />
http://www.competecoalition.com/files/LECG%20study.pdf<br />
2<br />
For example, at page 8 of their paper, Chandley and Hogan characterize the CMP as follows:<br />
“It is not an exaggeration, therefore, to describe this approach as akin to detailed less-thancost-of-service<br />
regulation.” APPA found these criticisms somewhat mystifying, given that the<br />
CMP retained a “single clearing price” (SCP) auction format, and expressly called for continuation<br />
of market-based rates for bilateral contracts.<br />
3<br />
This was in marked contrast to some limited informal feedback from the asset owner sector<br />
that APPA staff received, to the effect that the proposal, while not acceptable in its current<br />
form, was indeed a thoughtful and good faith proposal worth further discussion.<br />
iv APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
Against this backdrop of continued<br />
inadequate market oversight, are<br />
increasingly successful attempts by<br />
incumbent generation owners to<br />
develop new sources of revenue,<br />
either through changes to current<br />
market rules or through the creation<br />
of new markets – almost always<br />
over the strenuous objections of<br />
consumer and load-side<br />
representatives.<br />
issues that have since risen to prominence in RTO markets, and raise<br />
additional concerns for public power.<br />
Events over the past two- and- a-half years continue to illustrate the absence of<br />
adequate regulation and oversight of RTO markets by FERC. For example,<br />
APPA’s and others’ experiences with the development of RTO performance<br />
metrics illustrate the barriers to developing necessary measures that accurately<br />
assess the costs and benefits of wholesale electricity markets. In response to a<br />
2008 report by the Government Accountability Office (“GAO”) 4 , FERC issued<br />
a set of proposed RTO performance metrics in February 2010, developed<br />
largely in conjunction with the RTOs themselves. APPA and many others of<br />
the commenters stated that the proposed performance metrics were<br />
insufficient, primarily because they lacked essential measures of<br />
comprehensive revenue streams from wholesale markets, generator profits<br />
and accurate price-cost differentials. 5 The final measures that FERC approved<br />
were similar to those recommended by the RTOs and did not include such<br />
key measures. The ISO/RTO Council then provided a report to FERC that<br />
was essentially a recounting of the many achievements of RTOs. Hence, the<br />
entire exercise failed to meet the original intent of the GAO’s<br />
recommendation --— to accurately measure the validity of such claims about<br />
market benefits. 6<br />
Against this backdrop of continued inadequate market oversight, are<br />
increasingly successful attempts by incumbent generation owners to develop<br />
new sources of revenue, either through changes to current market rules or<br />
through the creation of new markets – almost always over the strenuous<br />
objections of consumer and load-side representatives. Such enhancements of<br />
revenue streams, however, are being implemented absent any measures to<br />
ensure a reliable supply of power in the future to justify the payment of such<br />
revenues.<br />
Illustrative of these types of controversies are the proposal for scarcity pricing<br />
4<br />
The GAO found that “FERC has not conducted an empirical analysis to measure whether<br />
RTOs have achieved these expected benefits or how RTOs or restructuring efforts more generally<br />
have affected consumer electricity prices, costs of production, or infrastructure investment.”<br />
Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional<br />
Transmission Organizations’ Benefits and Performance, GAO-08-987, September 2008, p.55,<br />
http://www.gao.gov/new.items/d08987.pdf.<br />
5<br />
Initial Comments of the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong> and the Electricity Consumers Resource<br />
Council, Docket AD10-5-000, Federal Energy Regulatory Commission, March 5, 2010,<br />
http://www.publicpower.org/files/PDFs/APPAELCONAInitialCommentsAD105352010asfiled.pdf<br />
6<br />
ISO/RTO Performance Metrics, Commission Staff Report, Docket No. AD10-5-000, Federal<br />
Energy Regulatory Commission, October 21, 2010, http://www.ferc.gov/legal/staffreports/10-21-10-rto-metrics.pdf.<br />
The ISO/RTO Council subsequently issued its report on the data required by the metrics.<br />
APPA’s response to that report is at: http://appanet.cms-plus.com/files/PDFs/APPAResponsetoRTOMetricsReport121310.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update v
in PJM, the recent battles over measures to prevent state-procured new<br />
generation resources from participating in ISO New England’s Forward<br />
Capacity <strong>Market</strong> (“FCM”) and PJM’s Reliability Pricing Model (“RPM”), and<br />
the bitter disputes in the PJM Interconnection (“PJM”) regarding the specific<br />
load forecasts that PJM uses in administering its RPM.<br />
But even more disturbing to APPA has been the reappearance of “RTOhopping,”<br />
i.e., the practice of transmission- owning utilities with affiliates that<br />
have unregulated generation units moving from one RTO to another to take<br />
advantage of more lucrative payments for their generation assets. The prime<br />
examples of this were First Energy’s migration from the Midwest Independent<br />
Transmission System Operator (“MISO”) to PJM, proposed in August 2009<br />
with full integration planned for June 2011, followed by Duke Energy’s June<br />
2010 proposal to move its Ohio and Kentucky transmission and generation<br />
assets (including jointly-owned assets) from MISO to PJM, expected to be<br />
completed in January, 2012. 7<br />
The desire of these companies to maximize the revenues from their<br />
unregulated generation assets is certainly understandable. And FERC’s<br />
decision to allow such transfers, 8 while deeply disappointing is also at least<br />
understandable, given the terms of the contracts under which these<br />
transmission owners had previously agreed to join MISO. What APPA had not<br />
expected, however, and what it finds both profoundly anti-consumer and<br />
deeply alarming, was the attitude of the current Chairman of FERC regarding<br />
these transfers. As reported in the October 22, 2010 Energy Daily (at 3)<br />
regarding the Duke Energy transfer:<br />
FERC Chairman Wellinghoff said there was nothing wrong with<br />
utilities switching RTOs, whether for capacity market payments or<br />
other reasons. It is healthy for utilities to evaluate “where is the most<br />
competitive RTO that provides them the best opportunity for their<br />
business models to operate,” he said. And from the RTOs’<br />
perspective, he said it was a good thing “to have other RTOs realize<br />
that there may be another RTO that may have a superior structure<br />
that is attracting more utilities and that they maybe should consider<br />
changing their structure.”<br />
When the concept of “competition” in RTO regions has devolved from<br />
determining which RTO (and RTO market designs) can best harness<br />
7<br />
FirstEnergy and Duke market integration materials are available at:<br />
http://www.pjm.com/markets-and-operations/market-integration.aspx<br />
8<br />
Order Addressing RTO Realignment Request and Complaint, Dockets ER09-1589-000 and<br />
EL10-6-000, 129 FERC 61,249 (December 17, 2009); and Order Addressing RTO Realignment<br />
Request ,Request, Dockets ER10-1562-000 and ER10-2254-000, 133 FERC 61,058 (October<br />
21, 2010).<br />
vi APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
competition to deliver just and reasonable prices to consumers (as the<br />
Federal <strong>Power</strong> Act (“FPA”) requires) 9 to which RTO can offer<br />
generation asset owners the most dollars to join their organization,<br />
something is badly amiss. FERC regulation of RTOs under the FPA has<br />
reached the point where, when the GAO criticized FERC for not<br />
sufficiently evaluating and assessing RTO market performance, FERC<br />
turned to the RTOs themselves to design “metrics” to measure their own<br />
performance, and then adopted those metrics with very few changes, 10<br />
as described above.<br />
Predictably, this lack of evenhandedness in balancing the interests of<br />
generation and load in the design of RTO markets, the application of RTO<br />
market rules, and FERC oversight of RTO markets and activities, has<br />
resulted in consternation and restiveness among load side interests. This<br />
has been seen most recently and clearly in the ongoing events in Maryland<br />
and New Jersey, two states in PJM that have been required to pay high rates<br />
in PJM’s RPM capacity auctions. Both states are located in transmissionconstrained<br />
areas of the PJM footprint. New Jersey Governor Chris Christie<br />
signed legislation in January, 2011 providing for a “self help” remedy in the<br />
form of mandated bilateral generation contract procurements for the<br />
utilities that provide default retail power supply service in New Jersey, to<br />
“anchor” the construction of new generation capacity. 11 The Maryland<br />
<strong>Public</strong> Service Commission issued a draft RFP for long-term contracts and<br />
indicated that it is strongly considering implementing a measure similar to<br />
New Jersey’s. 12 Because a key component of these states’ plans is to bid the<br />
resulting new generation into PJM’s capacity market auctions, thus<br />
potentially lowering the price, owners of existing generation in PJM (PJM<br />
<strong>Power</strong> Providers or “P3”) filed a complaint with FERC aimed at preventing<br />
new generators with bilateral contracts from seeking to lower capacity<br />
prices. 13 Following a drop in prices in the New England capacity market,<br />
9<br />
16 U.S.C. §§ 824d and 824e.<br />
10<br />
Notice Requesting Comments on RTO/ISO Performance Metrics, Docket AD10-5-000, 75<br />
Fed. Reg. 7,581 (February 22, 2010); Initial Comments of the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong><br />
and the Electricity Consumers Resource Council, Docket AD10-5-000, Federal Energy<br />
Regulatory Commission, March 5, 2010 http://www.publicpower.org/files/PDFs/APPAEL-<br />
CONInitialcommentsAD105352010asfiled.pdf; and ISO/RTO Performance Metrics, Commission<br />
Staff Report.<br />
11<br />
New Jersey P.L.2011, Chapter 9, Senate, No. 2381, §§1,3,4 - C.48:3-98.2 to 48:3-98.4 §5 -<br />
C.48:3-60.1, http://www.njleg.state.nj.us/2010/Bills/AL11/9_.PDF<br />
12<br />
Notice of Comment Period on Request for Proposals for New Generating Facilities , Case No.<br />
9214, Maryland <strong>Public</strong> Service Commission, December 29, 2010,<br />
http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfmServer-<br />
FilePath=C:\Casenum\9200-9299\9214\\34.pdf<br />
13<br />
Complaint and Request for Clarification Requesting Fast Track Processing, PJM <strong>Power</strong> Providers<br />
Group, Docket EL-20-000, Federal Energy Regulatory Commission, February 1, 2011,<br />
http://www.p3powergroup.com/siteFiles/News/BA60285E201B5659BBD906367C86FBC9.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update vii
the New England generators filed a similar complaint seeking to mitigate<br />
the effects of Connecticut’s or other states’ bidding of procured generation<br />
as a price taker (referred to as “out-of-market resources”). 14<br />
In response to these complaints both RTOs proposed changes in their<br />
respective capacity markets. In April 2011, FERC approved changes to PJM’s<br />
RPM that would make it very difficult for new natural gas-fired resources<br />
contracted for outside of RPM—- such as resources obtained under a state<br />
procurement program like New Jersey’s or by a municipal utility for selfsupply—-<br />
to bid into the auctions at zero. 15 Without the option to bid into<br />
an auction at zero, these resources now face the danger that they would not<br />
clear the auction, thus potentially endangering their construction. In New<br />
England’s FCM market, FERC also approved the ISO’s development of a<br />
minimum price requirement for bids from new resources into the capacity<br />
market 16 , which will likely have an similar effect similar to the approved<br />
RPM rule change.<br />
APPA notes that these state actions are consistent with APPA’s<br />
recommendation in the first edition of the CMP (at 17) that “state public<br />
service commissions establish competitive power supply procurement<br />
processes to develop diversified resource portfolios for incumbent [investorowned<br />
utility load- serving entities], with a significant portion of their power<br />
supplies being obtained under longer-term contracts or owned-generation<br />
arrangements.” APPA noted that such measures could “provide much<br />
needed price discipline in RTO-run centralized markets.” Id. The<br />
Commission’s recent rulings, however, seem to ensure that states will not<br />
have the necessary tools at their disposal to assure reasonable rates for<br />
electric power supply to their own citizens.<br />
The frustration in Maryland, New Jersey and other states (such as<br />
Connecticut) stems from a basic flaw in RTO-run centralized markets --—<br />
they do not sufficiently support new generation investment but instead<br />
overcompensate existing generators. While those supporting locational<br />
capacity markets claimed to regulators and load-side interests that such<br />
markets would send “price signals” to generators as to where to invest in<br />
new generation, there has been no demonstrated relationship between<br />
prices and investments in new resources. 17 Instead, consumers have paid<br />
14<br />
Motion to Intervene and Protest of the New England <strong>Power</strong> Generators <strong>Association</strong>, Docket<br />
ER10-787-000, Federal Energy Regulatory Commission, March 15, 2010,<br />
http://elibrary.ferc.gov/idmws/common/OpenNat.aspfileID=12292579<br />
15<br />
Order Accepting Proposed Tariff Revisions, Subject To Conditions, And Addressing Related<br />
Complaint, 135 FERC 61,022 (April 12, 2011),<br />
http://elibrary.ferc.gov/idmws/common/OpenNat.aspfileID=12617771<br />
16<br />
Order On Paper Hearing And Order On Rehearing, 135 FERC 61,029 (April 13, 2011),<br />
http://elibrary.ferc.gov/idmws/File_list.aspdocument_id=13909713<br />
viii APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
literally billions of dollars through these markets to incumbent generators<br />
with existing units. While it is true that these markets have supported<br />
development of new demand response resources, and existing generation that<br />
might have otherwise retired has stayed on line, it is questionable whether<br />
these benefits justify the very high associated costs.<br />
The failure of RTO-run centralized locational capacity markets to support<br />
substantial new generation investment leads directly to the most important<br />
reason why the industry now needs to engage in the “rational debate” on the<br />
design of RTO markets that APPA had hoped to spur in 2009 --— the likely<br />
retirement of a substantial portion of the nation’s coal-fired electric<br />
generation fleet in the next several years. The Environmental Protection<br />
Agency (“EPA”) is currently planning to issue a panoply of new and revised<br />
regulations in the 2010-20 time frame, dealing with everything from NOx,<br />
SO2 and mercury emissions to power plants’ continued use of once-through<br />
cooling, to storage and disposal of coal ash. The cumulative effect of these<br />
new regulations will likely make a substantial number of existing coal-fired<br />
generation units uneconomic to operate in the future. There are many<br />
estimates of the plant closures likely to occur, ranging from 30 to 70 gigawatts<br />
(GW) of coal generation within the next ten years, with most estimates<br />
trending towards the higher end of this range. 18<br />
RTO regions currently have excess generation capacity, due to the impacts of<br />
the recession and the payments made to keep existing generation units (some<br />
of them old and inefficient) in operation. But this situation could well<br />
change quickly once demand begins to increase if the recession eases, and as<br />
generation unit owners assess their units’ continued economic viability in<br />
17<br />
Despite the payment of $42 billion in the first seven auctions, actual new generation net of<br />
deactivations and retirements, has equaled just 0.5 percent of the total generation that has<br />
cleared the market and 3 percent of the average cleared in each auction. Moreover, a recent<br />
analysis shows that high prices within the constrained zones within PJM’s Reliability Pricing<br />
Model have not incented greater levels of new generation clearing the RPM auctions or existing<br />
plant upgrades, demand response, energy efficiency resources, and net imports offered in<br />
constrained zones. See Direct Testimony of James F. Wilson in Support of First Brief of the<br />
Joint Filing Supporters, Docket ER10-787, Federal Energy Regulatory Commission, July 1,<br />
2010, Section V, http://www.wilsonenec.com/FCM_Testimony_July_1.php<br />
18<br />
Studies of projected coal plant closures have been undertaken by: The North <strong>American</strong> Electric<br />
Reliability Corporation (10 - 35 GW of coal and 40 - 70 GW of all capacity by 2018), 2010<br />
Special Reliability Scenario Assessment, October, 2010, Table IV-6,<br />
http://www.nerc.com/files/EPA_Scenario_Final.pdf; Credit Suisse Equity Research (60 GW<br />
of coal capacity between 2013 and 2017), Growth From Subtraction: Impact of EPA Rules on<br />
<strong>Power</strong> <strong>Market</strong>s, September 23, 2010, http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf;<br />
The Brattle Group (50 – 66 GW of coal capacity by 2020), Potential Coal <strong>Plan</strong>t Retirements<br />
Under Emerging Environmental Regulations, December 8, 2010,<br />
http://www.brattle.com/_documents/UploadLibrary/Upload898.pdf, and FBR Capital (30 –<br />
70 GW in the next few years), EPA regs may shut 70,000 MW of U.S. coal plants: FBR, Reuters,<br />
December 13, 2010 http://www.reuters.com/article/2010/12/13/us-utilities-epa-coal-idUS-<br />
TRE6BC3JN20101213<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update ix
light of these new EPA regulations. The industry and its regulators need to<br />
start considering now how best to manage the transition to new, more<br />
efficient and cleaner generation. Current RTO locational capacity markets,<br />
with their relatively short (3-5 year) payout periods, simply cannot support the<br />
required new generation investment. Something will have to give, and<br />
relatively soon.<br />
In short, APPA believes it is now even more important than it was in 2009 that<br />
the industry begins the honest dialogue among its participants in RTO<br />
regions that will be needed to manage this transition to a lower-carbon<br />
generation future. APPA is therefore updating and re-releasing its CMP as its<br />
contribution to the debate. It urges other sectors of the industry to see this as<br />
a new opportunity to discuss the huge challenge before all of us, rather than<br />
to continue the partisan battles now taking place in RTO stakeholder<br />
processes and Commission proceedings. Such a result would be the triumph<br />
of hope over APPA’s past experience with its release of the first version of the<br />
CMP, but hope survives nonetheless.<br />
x APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
Executive Summary<br />
T<br />
his paper presents an updated version of the <strong>American</strong> <strong>Public</strong> <strong>Power</strong><br />
<strong>Association</strong>’s (APPA) <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> for reform of<br />
wholesale electricity markets administered by regional transmission<br />
organizations (RTOs). The plan, originally released in February 2009, was<br />
developed based upon results of investigative studies carried out under APPA’s<br />
Electric <strong>Market</strong> Reform Initiative (EMRI) and in consultation with APPA<br />
members, other market participants and electricity industry experts.<br />
APPA developed the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> to attempt to remedy the<br />
absence of meaningful competition and consumer protections under the<br />
current RTO market model, while still assuring resource adequacy. The<br />
changes proposed in this paper are only for regions with RTO-run centralized<br />
wholesale power supply markets under federal jurisdiction. APPA is not<br />
suggesting that geographic regions without RTOs adopt these proposals.<br />
Along with the proposed reforms, APPA is also recommending a moratorium<br />
on the development of new RTO markets, at least in the absence of strong,<br />
widespread RTO member support for them. APPA is recommending the<br />
following primary changes to the Day 2 RTO markets. These changes are<br />
intended to move these markets from de facto oligopolies to more<br />
competitive markets, while ensuring reliable electric service at just and<br />
reasonable rates.<br />
<strong>Power</strong> Supply <strong>Market</strong>s<br />
• Current RTO-run energy and ancillary services real-time and day-ahead<br />
markets would be replaced by an RTO-run “optimization” market, in<br />
which customers can could balance supply deficiencies or excess<br />
purchases, and generators can could sell excess generation.<br />
• Offers to sell into the optimization market for both energy and ancillary<br />
services would be limited to generators’ marginal costs of generation.<br />
Generators would be required to submit their unit-specific operating<br />
costs to the RTO market monitor in advance to provide cost support for<br />
their offers. Prices would be set initially using a cost-based single-clearing<br />
price mechanism, with evaluation of the results of that mechanism after<br />
three years of operation.<br />
• The optimization market would use a marginal cost-based, single-clearing<br />
price model for the purpose of generation resource commitment and<br />
dispatch.<br />
• Generator offers into the optimization market would be made public on<br />
the next operating day, including the identity of bidders.<br />
• FERC-jurisdictional power suppliers entering into bilateral contracts with<br />
load-serving entities (LSEs) in an RTO region would not be subject to<br />
cost-based restrictions, i.e., they could use market-based rates if they have<br />
obtained such authority from FERC. APPA recommends, however, that<br />
FERC separately evaluate generation market power for long-term power<br />
xii APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
supply products in determining seller eligibility for market-based rate<br />
authority.<br />
• Generators would be subject to a must-offer requirement into the<br />
optimization market for energy not already committed under bilateral<br />
contracts or LSE-owned generation arrangements (subject to forced<br />
outages, scheduled maintenance, and special rules for limited-run units).<br />
• Demand-side resources could sell into the optimization market, but<br />
would not be subject to a cost-based offer restriction; rather, they would<br />
take the single-clearing price that clears the market net of the foregone<br />
retail rate, assuming they have previously offered to reduce demand at<br />
that price level.<br />
Resource Adequacy<br />
• Existing RTO-administered locational capacity markets would be phased<br />
out over time and capacity would be supplied through bilateral contracts<br />
entered into by LSEs with resource suppliers (both generation and<br />
demand response), LSE-owned generation arrangements and LSEmanaged<br />
demand response.<br />
• The RTOs would determine and implement overall resource adequacy<br />
standards applicable to LSEs within the RTO footprint. States would have<br />
substantial input into RTO development of regional transmission plans<br />
and regional resource adequacy requirements.<br />
• States would establish resource acquisition processes to secure a<br />
diversified portfolio of generation and demand-side resources for stateregulated<br />
investor-owned utility (IOU) LSEs. In retail choice states,<br />
competitive procurements, including consideration of both LSE selfbuild/self-supply<br />
and third-party supplier options, would be conducted<br />
for state-regulated IOU LSEs, with an option for locally regulated LSEs to<br />
participate.<br />
• States and LSEs would be free to explore broader LSE resource<br />
procurement initiatives, such as regional procurements or LSE resource<br />
pooling.<br />
RTO Dispatch and Transmission Operation<br />
• RTOs would conduct centralized least-cost dispatch of generators based<br />
on actual marginal costs. Generators and demand response providers<br />
would be paid based upon contracted prices for quantities sold through<br />
the bilateral market. For quantities sold through the optimization<br />
market, generators and demand responders would receive the cost-based<br />
market-clearing price.<br />
• Data on bilateral contracts would be submitted to the RTO for the<br />
purposes of market monitoring, running feasibility tests to assess<br />
transmission adequacy, and developing regional transmission plans.<br />
• Financial transmission rights (“FTRs”) would be allocated to LSEs. Longwww.<strong>Public</strong><strong>Power</strong>.org<br />
APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update xiii
term FTRs would also be granted to support longer-term (e.g., 10-year)<br />
bilateral power supply arrangements and LSE-owned resources. Because<br />
such FTRs support physical transactions, they would be exempted from<br />
otherwise applicable collateral or margin posting requirements.<br />
• Existing transmission rights would be maintained to the maximum extent<br />
feasible.<br />
• RTOs would continue to ensure non-discriminatory open access to the<br />
transmission system.<br />
APPA recommends as part of its <strong>Plan</strong> that FERC conduct periodic reviews of<br />
wholesale power supply markets in RTO regions, to assess long-term price<br />
stability, possible exercises of market power, justness and reasonableness of<br />
rates, and reliability. To the extent that reformed RTO markets are not<br />
making adequate progress in providing balanced incentives and benefits to<br />
both generator and load interests, further reforms would need to be<br />
considered.<br />
xiv APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
I. Introduction<br />
T<br />
his paper presents the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong>’s (APPA)<br />
updated plan for reform of wholesale electricity markets administered<br />
by regional transmission organizations (RTOs). The initial plan was<br />
developed based upon results of investigative studies carried out under<br />
APPA’s Electric <strong>Market</strong> Reform Initiative (EMRI) and consultation with APPA<br />
members, other market participants, and electricity industry experts. The<br />
updated plan contains modifications suggested by two additional years of<br />
experience with RTO-administered centralized markets.<br />
APPA initiated EMRI in 2006 following a series of fundamental changes in the<br />
wholesale electricity markets. The Federal Energy Regulatory Commission<br />
(FERC) shifted its policy emphasis from ensuring non-discriminatory open<br />
access transmission service to implementing centralized RTO-run wholesale<br />
electric markets, with only limited wholesale price regulation. (A map of the<br />
geographic regions covered by the RTOs is shown below.)<br />
Meanwhile, many states implemented retail access programs to provide retail<br />
electric consumers with a choice of electricity providers. In many of these<br />
states, investor-owned utilities (IOUs) sold off their generating plants to third<br />
parties (in many cases, their unregulated affiliates), which can now sell their<br />
power at prices that are no longer tied to the costs of production, and are<br />
subject only to limited RTO “market mitigation” rules.<br />
Source: Federal Energy Regulatory Commission<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 1
In response to growing problems that public power utilities were experiencing<br />
obtaining power supplies in RTO regions with centralized power supply<br />
markets, APPA launched EMRI in March 2006 to investigate restructured<br />
wholesale electricity markets and develop needed reforms to those markets.<br />
Under this initiative, APPA commissioned a series of studies investigating the<br />
restructured RTO-run wholesale markets under federal jurisdiction. 19 Based<br />
on the results of these studies, APPA concluded that RTO-run centralized<br />
wholesale markets had substantial problems, and were not yielding “just and<br />
reasonable rates,” as the Federal <strong>Power</strong> Act (FPA) 20 requires. APPA therefore<br />
embarked on the development of potential reforms to these markets.<br />
A fundamental reason for restructuring of electricity markets was the<br />
expectation that the combination of open access transmission service and<br />
RTO-operated centralized wholesale markets would promote “competition.”<br />
This increased competition in turn would spur efficiencies and innovation,<br />
ensure adequate supplies and, most importantly, lower rates for consumers.<br />
But the EMRI studies and the real-world experience of consumers shows how<br />
the opposite has occurred. These deregulated markets produced both higher<br />
prices and higher profits than one would expect in a competitive market.<br />
Prices exceed those prevailing in the remaining regions that have not<br />
restructured and have instead retained cost-of-service regulation. The greatest<br />
beneficiaries of restructuring are not consumers, or the new, innovative<br />
companies that were promised to emerge under competition, but the owners<br />
of large fleets of previously regulated, largely depreciated generation units.<br />
These central concerns still remain over more than two years after the release<br />
of APPA’s <strong>Competitive</strong> <strong>Market</strong> plan (“CMP” or “<strong>Plan</strong>”). In fact, APPA<br />
concluded that several significant developments have necessitated updates to<br />
the CMP. Those developments include the capacity market difficulties, the<br />
increasing role of demand response, greater concerns over transmission costs,<br />
planning and rate incentives, and additional and increasingly complex RTO<br />
market proposals.<br />
Another significant change is that the recession of the past two years has<br />
reduced demand, which in turn lowered energy prices and lessened previous<br />
concerns about potential supply shortages in the short term. Because these<br />
price drops were the result of external economic factors, they do not by<br />
themselves affirm or negate the success of the markets in providing benefits<br />
for consumers. The absence of a connection between RTO markets and<br />
recession-induced price decreases, however, have has not stopped supporters<br />
19<br />
The results of these studies are available on the EMRI section of APPA’s Web site at: www.<strong>Public</strong><strong>Power</strong>.org/emri.cfm<br />
20<br />
FPA Sections 205 and 206, 16 U.S.C. §§ 824d, 824e.<br />
2 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
of the markets from citing these lower prices as evidence of the<br />
“competitiveness” of the markets. 21<br />
While wholesale energy prices fell in 2009 and began to rebound in 2010,<br />
overall retail prices in both in regulated and deregulated states have<br />
continued to increase. But prices in deregulated states within RTO regions<br />
have been 50 percent greater than regulated states in the past two years. 22<br />
Part of the reason for this wholesale/retail disparity is the many nongeneration<br />
costs that directly affect retail rates, such as local distribution costs.<br />
Another factor is that indices of wholesale energy prices by themselves do not<br />
provide a complete picture of all components of generation costs. Sources of<br />
wholesale market revenue to generators include capacity market, ancillary<br />
service, and uplift payments, as well as revenue from bilateral contracts, such<br />
as those arranged for provision of standard offer service.<br />
It is highly likely that the declines in wholesale prices reflect just a temporary<br />
drop that affects primarily the energy spot markets, and not other RTO<br />
markets. First, an increasing amount of revenue has been flowing through the<br />
capacity markets, and prices in the constrained areas in the PJM 23 and NY<br />
ISO 24 locational capacity markets have been increasing. Second, the pending<br />
closure of some coal plants, especially in RTO regions, in response to EPA<br />
21<br />
For example, the Electric <strong>Power</strong> Supply <strong>Association</strong> (EPSA), in a statement on the 2009 market<br />
monitor reports, asserted that: “The annual reports note that the organized wholesale<br />
markets are appropriately reflecting dramatically lower fuel prices with electricity prices dropping<br />
by roughly 50 percent from 2008 levels across the markets. The reports once again underscore<br />
the benefits to consumers of independent operation of the transmission system and<br />
markets that are quickly responsive to lower costs.” Organized Wholesale <strong>Market</strong>s Are <strong>Competitive</strong><br />
and Delivering Benefits to Consumers, EPSA <strong>Power</strong>Fact, August 25, 2010,<br />
http://www.epsa.org/forms/documents/DocumentForm<strong>Public</strong>/viewid=16CC400000002.<br />
In 2009, Joel Malina, Executive Director of COMPETE, stated that: “In competitive electricity<br />
markets all over the country electricity prices are on the downturn. This evidence should put<br />
to rest the superficial arguments suggesting that competitive markets aren’t working.” Rates<br />
Continue to Decrease in <strong>Competitive</strong> <strong>Market</strong>s, Including Ohio, Massachusetts, Pennsylvania,<br />
New York, Illinois and Maryland, Compete Coalition, June 10, 2009, http://www.competecoalition.com/newsroom/rates-continue-decrease-competitive-markets-including-ohio-massachusetts-pennsylvania-new-y<br />
22<br />
Retail Electric Rates in Deregulated and Regulated States: 2010 Update, APPA, March 2011,<br />
http://www.publicpower.org/files/PDFs/RKWFinal2010.pdf<br />
23<br />
As determined by the capacity market auctions, prices in the transmission-constrained areas<br />
are scheduled to increase in June 2012, and again in June 2013, more than doubling the June<br />
2011 price. See PJM’s Base Residual Auction Results at http://www.pjm.com/markets-and-operations/rpm/rpm-auction-user-info.aspx#Item06.<br />
24<br />
Capacity prices in New York City increased by 92 and 57 percent in the second and third<br />
quarters of 2010 and compared to the same quarters for 2009, while falling slightly in other<br />
areas. Quarterly Report on NY ISO Electricity <strong>Market</strong>s, Second Quarter 2010, July 2010, p. 3,<br />
Third Quarter 2010, October 2010, p. 3; http://www.nyiso.com/public/webdocs/documents/mmu_quarterly_reports/2010/NYISO_Quarterly_Report_2010Q2.pdf;<br />
and<br />
http://www.nyiso.com/public/webdocs/documents/mmu_quarterly_reports/2010/NYISO_<br />
Quarterly_Report_2010Q3.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 3
egulations is likely to constrain supply and result in the dispatch of more<br />
expensive power plants, increasing both energy and capacity prices. 25<br />
Transitory price decreases should not affect conclusions about the overall<br />
costs and benefits of the RTO-operated electricity markets. Evaluating costs<br />
and benefits requires a determination of whether prices produced in the<br />
RTO-operated markets are what one would expect to see from a truly<br />
competitive market, as indicated by prices being equal to (or at least close to)<br />
the actual costs of production, accounting for a contribution to fixed costs. In<br />
contrast, two APPA analyses showed that high profits continued in 2009 and<br />
2010 for the largest owners of unregulated generation in PJM, as measured by<br />
net operating income and returns on equity. These high profits indicate that<br />
rates remain substantially above the costs of production of electricity incurred<br />
by these merchant generators. 26<br />
The impact of RTO markets on generator profits, and in turn on the<br />
consumer, varies depending upon whether the state regulatory regime<br />
employs retail choice or vertical integration with an obligation to serve<br />
customers. For example, in the Midwest region almost all LSEs fall into this<br />
second category. For these generation-owning utilities with an obligation to<br />
serve, the excess profits recovered by baseload generators in the RTOoperated<br />
markets are passed back to the consumer, not retained by<br />
shareholders as profit. Two companies owning merchant generation located<br />
within the Midwest ISO, First Energy and Duke Energy, are in the process of<br />
moving their transmission and generation assets from MISO to PJM. 27 The<br />
greater capacity prices in PJM’s market will provide a more lucrative earnings<br />
opportunity for these companies. In an apparent attempt to avoid future<br />
departures, and support the entrance of the Entergy operating companies,<br />
MISO is in the process of developing a proposal for a centralized forward<br />
25<br />
Credit Suisse projects that the likely supply constraints resulting from the coal plant closures<br />
would increase power prices by at least $5 per MWh in PJM-West and MISO, as well as putting<br />
upward pressure on capacity prices. Growth From Subtraction: Impact of EPA Rules on <strong>Power</strong><br />
<strong>Market</strong>s, Credit Suisse Equity Research, September 23, 2010, pp. 47-48,<br />
http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf<br />
26<br />
2009 Financial Performance of Owners of Unregulated Generation: High Profits Earned in<br />
Restructured Wholesale Electricity <strong>Market</strong>s During the Recession, APPA, May 2010,<br />
http://www.publicpower.org/files/PDFs/2009FinancialPerformanceMay2010.pdf; and Financial<br />
Performance of Owners of Unregulated Generation in PJM: 2010 Update, www.publicpower.org/files/PDFs/FinancialPerformance2010UpdateMay2011.pdf<br />
27<br />
FirstEnergy Service Company’s move into PJM is planned to be completed by June 1, 2011,<br />
and will include the <strong>American</strong> Transmission Systems, Inc. (ATSI) transmission assets, the regulated<br />
distribution utilities (The Cleveland Electric Illuminating Company, Ohio Edison<br />
Company, The Toledo Edison Company, and Pennsylvania <strong>Power</strong> Company) and the merchant<br />
generation owner, FirstEnergy Solutions. Duke Energy’s move is planned for January 1,<br />
2012, and includes the transmission assets of Duke Energy Ohio, Inc. and Duke Energy Kentucky,<br />
Inc., as well as the Duke Energy generation assets. See the <strong>Market</strong> Integration section<br />
of PJM’s web site at http://www.pjm.com/markets-and-operations/market-integration.aspx<br />
4 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
capacity market, resembling PJM’s Reliability Pricing Model. 28<br />
APPA developed its CMP to attempt to remedy the absence of meaningful<br />
competition and consumer protections under the current RTO market<br />
model, while still assuring resource adequacy. The changes proposed in this<br />
paper are only for regions with RTO-run centralized wholesale power supply<br />
markets under federal jurisdiction. APPA is not suggesting that geographic<br />
regions without FERC-jurisdictional RTOs adopt these proposals. Along with<br />
the proposed reforms, APPA is also recommending a moratorium on the<br />
development of new RTO markets, at least in the absence of strong,<br />
widespread RTO member support for them.<br />
Although the changes APPA proposes would require a lengthy<br />
implementation period, APPA made substantial efforts to work within the<br />
existing RTO structure. Current RTO market structures are extremely<br />
complicated and cannot be easily modified, due in large part to a stakeholder<br />
process that is heavily influenced by generation owners. To the extent that<br />
current features of RTO markets are maintained in the CMP, this should not<br />
be construed as an APPA endorsement of such features, but rather<br />
recognition that a complete overhaul of the existing markets would be very<br />
difficult to accomplish.<br />
Goals of the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong><br />
APPA intends that its <strong>Plan</strong> would produce the following outcomes:<br />
• Increase the availability of long-term bilateral power supply contracts<br />
(e.g., a 10-year term) and opportunities for LSE-owned generation, in<br />
turn enhancing the viability of financing new generation and renewable<br />
energy technologies.<br />
• Reduced opportunities for market participants to exercise market power.<br />
• Transmission planning and construction processes that support longterm<br />
bilateral contracts/generation ownership and the new generation<br />
resources developed with the support of such power supply<br />
arrangements.<br />
• Greater opportunities for LSEs to hedge congestion and reduced<br />
speculative opportunities for financial-only market participants.<br />
• Reduced power supply price volatility and wholesale electricity rates that<br />
better comport with the just and reasonable standard of the Federal<br />
<strong>Power</strong> Act.<br />
28<br />
Midwest ISO Resource Adequacy Enhancements Proposal, Supply Adequacy Working Group,<br />
Midwest ISO, December 9, 2010, https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2010/20101209/20101209%20SAWG%20Item%2003<br />
%20Midwest%20ISO%20RA%20Enhancement%20Proposal.PDF; and other materials from<br />
the MISO Supply Adequacy Working Group meetings, https://www.midwestiso.org/Library/MeetingMaterials/Pages/SAWG.aspx<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 5
• Resource adequacy standards, increased bilateral contracting, use of<br />
owned generation, and an optimization market that together would<br />
improve the reliability of electricity service.<br />
6 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
II. Background<br />
T<br />
his plan originated in a proposal, first presented in APPA’s<br />
February 2008 paper “Consumers in Peril,” 29 to restructure<br />
current “Day Two” RTOs as “Day One” RTOs. 30 After careful<br />
investigation and refinement of this concept, APPA decided that the best<br />
approach would be to develop a hybrid of the best elements of both RTO<br />
structures. Current Day Two RTOs operating in the United States include<br />
the PJM Interconnection (“PJM”), the Midwest Independent Transmission<br />
System Operator (“MISO”), ISO-New England (“ISO-NE”), and the New<br />
York Independent System Operator (“NYISO”) and the California ISO<br />
(“CAISO”). The Southwest <strong>Power</strong> Pool (“SPP”) is currently the only<br />
example of a FERC-approved Day One RTO. 31 For the remainder of this<br />
paper, the term RTO will be used to refer to a Day Two RTO. This paper<br />
will not delve into all of the problems LSEs have experienced with RTOs.<br />
To briefly summarize, the CMP was developed to remedy the most<br />
problematic aspects of RTO markets at the time, which are briefly outlined<br />
below and discussed in greater detail in Consumers in Peril: 32<br />
• The use of bid-based offers into the day-ahead and real-time markets<br />
provides opportunities for potential exercises of market power through<br />
the use of strategic bidding strategies, and the absence of any real<br />
relationship between prices and marginal costs reduces the price<br />
transparency needed for true competition.<br />
• The lucrative nature of the RTO-operated energy and capacity markets<br />
had has produced supra-competitive profits and has made incumbent<br />
sellers reluctant to enter into long-term bilateral power supply contracts<br />
at prices not directly linked to RTO-run spot market prices (plus<br />
substantial premiums in some cases). While new market entrants are<br />
now interested in long-term power supply contracts to support the<br />
financing of their generation projects, it is difficult for them to find<br />
29<br />
“Consumers in Peril: Why RTO-Run Electricity <strong>Market</strong>s Fail to Produce Just and Reasonable<br />
Electric Rates,” APPA, February 2008 available at:<br />
http://www.publicpower.org/files/PDFs/ConsumersinPeril.pdf . The policy recommendation<br />
to restructure RTO markets appears in Section 5, which is the focus of this document.<br />
30<br />
A “Day Two” RTO refers to a market structure where the RTO manages the transmission grid<br />
within its footprint to ensure non-discriminatory transmission access and reliability, runs centralized<br />
markets for energy (day-ahead and real-time) priced using locational marginal pricing<br />
concepts, and provides financial transmission rights (FTRs) to hedge the associated<br />
transmission congestion costs. Depending on the market design, a Day Two RTO may also<br />
run centralized markets for ancillary services and capacity. A Day One RTO does not administer<br />
centralized spot markets, except perhaps for a balancing market, but does oversee management<br />
of the transmission grid for reliability and open-access purposes.<br />
31<br />
SPP is has announced its intent to implement a Day Two market, and the most recent estimate<br />
for implementation is March 2014. Integrated <strong>Market</strong>place Project Milestones, SPP <strong>Market</strong><br />
Working Group, October 25, 2010,<br />
http://www.spp.org/section.aspgroup=1985&pageID=27<br />
32<br />
See Ch. 4 of “Consumers in Peril: Why RTO-Run Electricity <strong>Market</strong>s Fail to Produce Just and<br />
Reasonable Electric Rates.”<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 7
LSEs in restructured states that are able and willing to enter into longterm<br />
contracts to support such projects, due to the shorter-term nature<br />
of retail default supply regimes.<br />
• Excessive reliance by RTOs on often ineffective market and pricing<br />
signals and incentives to address transmission congestion and<br />
anticipated capacity shortfalls has substantially increased costs to<br />
electric consumers over what they would otherwise be.<br />
• Locational capacity markets are producing high capacity prices and<br />
opportunities for economic withholding, leading to substantial<br />
overpayments for capacity retention and additions.<br />
• Hedge funds, investment banks and other financial entities are<br />
participating in RTO markets through Financial Transmission Rights<br />
(“FTR”) auctions and virtual bids in spot markets, potentially increasing<br />
costs to consumers through their speculative activities.<br />
Moreover, since the issuance of APPA’s original CMP, actions by states to<br />
find alternative means to the centralized capacity markets to develop<br />
needed generation at reasonable prices have elicited vehement protests by<br />
generators, resulting in FERC-approved changes to the capacity market<br />
rules to prevent such state actions.<br />
All of these problems point to markets that are inherently uncompetitive,<br />
requiring significant interventions from market monitors and other<br />
regulators to keep generators from exercising overt market power and<br />
raising prices even during non-peak periods. Even with aggressive market<br />
monitoring, these RTOs’ market rules and institutions have created a<br />
system where the benefits of competition flow disproportionately to<br />
owners of existing generation.<br />
FERC and the RTOs have been largely unwilling to investigate and<br />
acknowledge the problems with these markets. 33 In response to a 2008<br />
Government Accountability Office (“GAO”) report, FERC issued a set of<br />
proposed RTO performance metrics in February 2010. In its comments on<br />
these metrics, filed jointly with the Electricity Consumers Resource<br />
Council, APPA stated that the proposed “performance metrics shed little<br />
33<br />
For example, a 2008 study by the Government Accountability Office (GAO) found that<br />
“FERC has not conducted an empirical analysis to measure whether RTOs have achieved<br />
these expected benefits or how RTOs or restructuring efforts more generally have affected<br />
consumer electricity prices, costs of production, or infrastructure investment.” Electricity Restructuring:<br />
FERC Could Take Additional Steps to Analyze Regional Transmission Organizations’<br />
Benefits and Performance, p.55, GAO-08-987, September 2008 (“GAO Report”),<br />
http://www.gao.gov/new.items/d08987.pdf.<br />
34<br />
Initial Comments of the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong> and the Electricity Consumers<br />
Resource Council, Docket No. AD10-5-000, Federal Energy Regulatory Commission, March 5,<br />
2010. www.publicpower.org/files/PDFs/APPAELCONInitialCommentsAD1OS352010asfiled.pdf<br />
8 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
light on whether such prices are just and reasonable and reflect levels that<br />
would be produced in a truly competitive market.” 34 Almost half of the<br />
commenters stated that the performance metrics were insufficient. 35<br />
While the Commission on October 21, 2010, issued a Staff Report on<br />
ISO/RTO Performance Metrics, 36 the metrics set out in that report<br />
continued to omit the fundamental measure requested by APPA and<br />
others -- the profits earned by generators from all wholesale electricity<br />
markets. In response to the FERC staff metrics, the ISO/RTO Council<br />
provided a report to FERC that was essentially an assertion of the many<br />
achievements of RTOs, a number of which were unrelated to or<br />
unsubstantiated by the actual data presented in the rest of the report. 37<br />
FERC then issued a Report to Congress essentially summarizing the RTOs’<br />
own reports. 38<br />
In the continued absence of any meaningful FERC investigation into the<br />
operation of RTO-run centralized markets and their benefits to<br />
consumers, each difficulty in the markets is met by the RTOs themselves<br />
with a new, increasingly complicated market and/or pricing incentive,<br />
often approved by FERC without sufficient scrutiny of how or whether this<br />
new feature will achieve the desired goals. For example, in the face of<br />
looming shortfalls in generation capacity, RTOs in the past responded only<br />
to complaints of generators that RTO mitigation rules and protocols<br />
prevent them from earning sufficient revenues in the energy market to<br />
recover the fixed costs or going-forward costs of generating units (the<br />
“missing money” problem). In response, the RTOs have created a number<br />
of secondary markets, such as those for locational capacity and ancillary<br />
services. A number of reports have challenged the validity of the missing<br />
money problem and suggested that these secondary markets are even less<br />
35<br />
Reply Comments of the <strong>American</strong> <strong>Public</strong> <strong>Power</strong> <strong>Association</strong> and the Electricity Consumers<br />
Resource Council, Docket No. AD10-5-000, Federal Energy Regulatory Commission, March<br />
19, 2010,<br />
http://www.publicpower.org/files/PDFs/APPAELCONAD105ReplyComments31910asfiled.p<br />
df<br />
36<br />
ISO/RTO Performance Metrics, Commission Staff Report, Docket No. AD10-5-000, Federal<br />
Energy Regulatory Commission, October 21, 2010, http://www.ferc.gov/legal/staffreports/10-21-10-rto-metrics.pdf.<br />
The ISO/RTO Council subsequently issued its report on the data required by the metrics.<br />
APPA’s response to that report is at: http://appanet.cms-plus.com/files/PDFs/APPAResponsetoRTOMetricsReport121310.pdf<br />
37<br />
http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-<br />
003829518EBD%7D/2010%20ISO-RTO%20Metrics%20Report.pdf. For APPA’s response to<br />
the report, see APPA Calls Recently Released ISO/RTO <strong>Market</strong> Report ‘Inadequate’, News<br />
Release, December 13, 2010, http://appanet.cms-plus.com/files/PDFs/APPAResponsetoR-<br />
TOMetricsReport121310.pdf<br />
38<br />
Performance Metrics for Independent System Operators and Regional Transmission Organizations,<br />
Federal Energy Regulatory Commission, Office of the Chairman, April 2011,<br />
http://www.ferc.gov/industries/electric/indus-act/rto/metrics/report-to-congress.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 9
competitive than RTO-run spot energy markets. 39 And despite the very<br />
substantial dollars paid, these markets have resulted in few new generation<br />
projects.<br />
The most recent example of yet another layer of a complex pricing incentive<br />
with the potential to yield lucrative results for generators rather than<br />
reliability benefits is PJM’s June 2010 “scarcity pricing” proposal. 40 Under this<br />
proposal, energy prices could climb up to $2,700 per megawatt-hour<br />
(compared to the current cap of $1,000) during times when operating<br />
reserves dip below a threshold level. PJM’s <strong>Market</strong> Monitor described the<br />
proposal as a “proposed radical alteration of the PJM market design in a<br />
manner that would raise the overall price of wholesale electric service in PJM<br />
with no corresponding benefit to its wholesale customers.” 41 Further<br />
complicating the array of new markets is that they are increasingly linked to<br />
each other. Scarcity pricing, for example, would directly impact both the<br />
locational capacity and reserves markets.<br />
FERC also ordered in Docket No. RM10-17-000 42 that RTOs are to pay<br />
demand response resources bidding directly into RTO wholesale energy<br />
markets the “full LMP” (locational marginal price) in all hours, as long as<br />
such dispatch of the demand resource passes a net benefits test. This payment<br />
of LMP has no offset to reflect the fact that demand response resources are<br />
avoiding the cost of purchasing power from their LSEs, even though these<br />
LSEs are incurring the costs to stand ready to serve the retail customers<br />
participating in such wholesale demand response bids. Aside from the<br />
39<br />
See, for example, T. Mount, Investment Performance in Deregulated <strong>Market</strong>s for Electricity:<br />
A Case Study of New York State, report for APPA, September 2007. Available at:<br />
http://www.publicpower.org/files/PDFs/StudyMountEMRIreportNYISOCapacity09%2D07.p<br />
df. Also, see James Wilson, Raising the Stakes on Capacity Incentives: PJM’s Reliability Pricing<br />
Model, report for APPA, February 2008, available at<br />
http://publicpower.org/files/PDFs/RPMreport2008.pdf. Reports from the PJM market<br />
monitor also concluded that the capacity markets are often not competitive. For example,<br />
Joseph Bowring, PJM’s market monitor, concluded that “the market design for capacity leads,<br />
almost unavoidably, to structural market power in the capacity market. The capacity market is<br />
unlikely ever to approach a competitive market structure in the absence of a substantial and<br />
unlikely structural change that results in much greater diversity of ownership.” Analysis of the<br />
2013-2014 RPM Base Residual Auction, Monitoring Analytics, July 14, 2010, p.1,<br />
http://www.monitoringanalytics.com/reports/Reports/2010/Analysis_of_2013_2014_RPM_<br />
Base_Residual_Auction_20100714.pdf<br />
40<br />
PJM Interconnection, L.L.C., Compliance Filing, Docket ER09-1063-006 , Federal Energy Regulatory<br />
Commission, June 18, 2010,<br />
http://elibrary.ferc.gov/idmws/file_list.aspaccession_num=20100621-0201<br />
41<br />
Protest and Compliance Proposal of the Independent <strong>Market</strong> Monitor for PJM, Docket ER09-<br />
1063-006 , Federal Energy Regulatory Commission, July 18, 2010, p. 2,<br />
http://elibrary.ferc.gov/IDMWS/File_list.aspdocument_id=13832963,<br />
42<br />
Order No. 745, Demand Response Compensation in Organized Wholesale Energy <strong>Market</strong>s,<br />
134 FERC 61,187, 76 Fed. Reg. 16,658 (March 24, 2011). The net benefits test calls for the<br />
full LMP to be paid to demand response resources when the cost of payments to demand response<br />
is outweighed by the benefits of the decrease in LMP as a result of reduction in load.<br />
10 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
difficult measurement and verification issues that payment of such dollars to<br />
entities that are reducing their retail energy usage raises, there is the separate<br />
question of whether the availability of such dollars at wholesale undermines<br />
retail efforts to implement demand response using time-differentiated prices,<br />
and the substantial investments, e.g., smart grid installations, that often<br />
accompany such efforts. While APPA certainly understands the desire to<br />
foster demand response as a resource, retail and wholesale programs and<br />
pricing need to be harmonized, not enacted in a piecemeal and conflicting<br />
fashion. Moreover, the implications of relying on increasingly high levels of<br />
demand response to provide the equivalent of generation capacity needs to<br />
be fully understood, given the absolute need to maintain reliable RTO<br />
operations.<br />
The layering on of new markets and pricing policies has created such a level<br />
of complexity that highly sophisticated entities have a built-in advantage in<br />
participating in RTO markets. Such complexity also impairs transparency and<br />
makes the task of market monitoring more difficult.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 11
III. Overview of Proposed <strong>Market</strong> Structure<br />
A<br />
PPA developed its <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> to support the following<br />
design goals:<br />
• Reduced opportunities for the exercise of market power, and<br />
sufficient data transparency to identify market power abuses;<br />
• For load not served by owned resources, an increased emphasis on longterm<br />
bilateral contracts (e.g., 5-10 years or longer) to support reliable<br />
service to customers at reasonable rates and to finance needed new<br />
generation and demand response resources, with minimal dependence<br />
on short-term energy markets to obtain power supplies;<br />
• Provision of open-access non-discriminatory transmission service;<br />
• Transmission and resource planning to meet reliability and<br />
environmental stewardship goals over time at the lowest reasonable cost<br />
from the most feasible set of resources, rather than merely to support<br />
long-distance, short-term transactions or the agendas of particular<br />
transmission or generation project developers; and<br />
• Minimization of market and operations complexity, and maximum<br />
procedural and data transparency for market participants, regulators and<br />
the general public.<br />
To accomplish these goals, APPA recommended that current RTO Day Two<br />
markets be reformed to retain the beneficial functions of RTOs, while<br />
modifying or phasing out problematic market design features. Under this<br />
plan, an RTO would offer transmission service to support open access to the<br />
transmission system, operate a marginal cost-limited single-clearing price<br />
“optimization market” for short-term procurement of energy and ancillary<br />
services, implement RTO-determined region-wide resource adequacy<br />
requirements, and plan for transmission facilities and service needed to<br />
support LSE-owned and contracted-for resources. Longer-term bilateral<br />
agreements between LSEs and generators/demand-side providers and LSEowned<br />
resource arrangements would be the primary methods of procuring<br />
resources.<br />
APPA concluded, based on communications with APPA’s members and<br />
observations of the current markets, that it would be very difficult to radically<br />
overhaul the current RTO-operated markets. In particular, it would be<br />
difficult to revert to the use of physical transmission rights rather than<br />
financial rights. To do so would upend numerous contracts and arrangements<br />
to serve load, as well as planned and ongoing construction of power plants.<br />
APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> therefore would include the following<br />
features, which are described in greater detail in this paper:<br />
• RTO operation of a residual, marginal cost-limited single-clearing price<br />
“optimization market” for balancing and short-term procurement of<br />
energy and ancillary services, but without limitations on the quantity of<br />
12 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
power sold through the optimization market.<br />
• Use of longer-term bilateral agreements and resource ownership as the<br />
primary methods of obtaining generation and demand-side resources.<br />
• <strong>Power</strong> procured through the bilateral contracts would continue to clear<br />
through the RTO-operated energy markets, with a financial settlement<br />
for the differences made by the contract parties outside of the RTO<br />
market.<br />
• Non-discriminatory open access to the transmission system and provision<br />
of long-term transmission rights to support LSE resource arrangements.<br />
• Provision of data on generator costs and optimization market offers to<br />
the public on a timely basis.<br />
• Centralized RTO dispatch of generation, using actual marginal-cost data<br />
as the basis of dispatch, rather than bid-based offers, but retaining the<br />
single-clearing price feature.<br />
• Phase-out of existing locational capacity markets over a time period long<br />
enough to ensure that existing obligations are fulfilled.<br />
• Phase-in of RTO-determined resource adequacy requirements for all<br />
LSEs to be met through portfolios of generation, demand response and<br />
energy efficiency resources.<br />
• State supervision of resource procurement for state-regulated IOU LSEs<br />
in retail access states, with emphasis on developing a diverse portfolio of<br />
resources of varying fuel types and terms.<br />
• <strong>Public</strong> reporting by FERC of RTO market performance metrics that at a<br />
minimum include data on revenues earned and costs incurred by<br />
generation units.<br />
The purpose of emphasizing longer-term bilateral contracts and generation<br />
ownership arrangements is to make the market structure more compatible<br />
with current financial realities and longer-range system planning for<br />
generation, transmission and demand response. Under the current market<br />
structure, investment decisions must be based on far-forward expectations of<br />
spot and capacity market prices, the volatility of which may discourage the<br />
development of appropriate risk-management products and practices. 43<br />
The RTO would continue to act as a regional transmission-management<br />
entity, but its operations would shift in focus to supporting bilateral resource<br />
contracts and owned- generation arrangements, rather than operating<br />
expansive centralized spot markets. The RTO would continue to dispatch<br />
generation centrally to ensure open-access and reliability, but would provide<br />
long-term transmission rights (“LTTRs”) more compatible with the use of<br />
bilateral and resource ownership arrangements for long-term power supply.<br />
The RTO would perform residual centralized real-time optimization market<br />
43<br />
L.B. Lave, J. Apt and S. Blumsack, Deregulation/Restructuring Part I: Re-Regulation Will Not<br />
Fix the Problems, Electricity Journal 2007, 20 (8), pp. 9 – 22.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 13
functions. APPA expects, however, that under its proposal, sales in the<br />
optimization market would constitute a smaller portion of total energy sales.<br />
Finally, the distribution side of the market would not change substantially,<br />
with regulated distribution utilities still responsible for physical delivery of<br />
power supplies to end-use customers. 44<br />
The reforms laid out in this paper could not be implemented within a short<br />
time frame. It has been over 10 years since Order No. 2000 was issued,<br />
encouraging the initial formation of RTOs. The problems with RTO markets<br />
have been building ever since, and would take a number of years to address.<br />
In recent years, RTO markets have proliferated, increasing the complexity of<br />
undertaking any reforms. A number of complex FERC proceedings would be<br />
required to develop and approve tariff changes for each RTO, many of which<br />
are likely to be contentious. Moreover, there are differences among the RTOs<br />
themselves. Implementation of the APPA <strong>Plan</strong> would therefore need to be<br />
tailored on an individual RTO basis. But the longer the industry and FERC<br />
wait to begin this important task, the longer it will be before consumers begin<br />
to see the benefits of the needed market reforms.<br />
APPA recommends as part of its <strong>Plan</strong> that FERC conduct periodic reviews of<br />
wholesale power supply markets in RTO regions, to assess long-term price<br />
stability, possible exercises of market power, justness and reasonableness of<br />
rates, and reliability. These reviews should encompass a wide array of<br />
performance metrics, including measures of profitability.<br />
44<br />
Third-party retail suppliers may have a diminished role in the new market regime. Retail access<br />
policy decisions should still be up to individual states, but competitive retail suppliers<br />
would need to be willing and able to meet longer-term resource adequacy requirements applicable<br />
to LSEs, either directly or through arrangements with third parties.<br />
14 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
IV. Role of State Regulatory Agencies<br />
W<br />
hile much of this paper is focused on the policy decisions FERC and<br />
the RTOs must make regarding wholesale market design and<br />
regulation, needed reforms to the wholesale markets cannot be<br />
accomplished without parallel changes to retail choice state policies. As<br />
discussed earlier, there is a significant difference in the degree to which<br />
consumers are impacted by RTO markets in states where utilities are vertically<br />
integrated and those where the bulk of the power is generated by unregulated<br />
power plants. In fact, events over the last few years make clear that problems<br />
in the retail access states are the most likely impetus for needed market<br />
reforms. Since states are closest to retail customers and see the adverse<br />
impacts of federal RTO policies first hand, they are more likely to seek<br />
reforms to improve RTO operations in their regions. These recommendations<br />
are therefore directed at retail access states with a high percentage of power<br />
from merchant generation. Retail access policies would still be left up to<br />
individual states, but, under the APPA <strong>Plan</strong>, competitive LSEs providing<br />
service in retail access states would have to meet the more rigorous resource<br />
adequacy requirements applicable to LSEs, either directly or through<br />
arrangements with third parties.<br />
The power purchases that incumbent non-vertically integrated IOU LSEs in<br />
retail access states make to support default supply service to retail customers<br />
that have not chosen a third-party supplier (often called “standard offer<br />
service” or SOS) have a substantial impact on wholesale market prices. In<br />
such states, the power supplies that incumbent LSEs use to provide SOS are<br />
typically purchased through state-run auctions for relatively short-term<br />
(usually two-to four-year) contracts. 45 As discussed later in this plan, the prices<br />
offered under these contracts are frequently based on forward projections of<br />
the prices likely to be set in RTO-run centralized spot markets. The relatively<br />
short-term nature of the SOS procurement auctions have therefore actually<br />
reinforced the connection between RTO-run spot market prices and bilateral<br />
contract prices, rather than allowing bilateral contract prices to act as a check<br />
on spot market prices. Generators selling under SOS auction contracts<br />
effectively obtain the benefits of RTO spot market pricing, as well as<br />
additional risk premiums included in the auction prices. Given such profit<br />
opportunities, it is not surprising that other LSEs and large end users<br />
attempting to procure wholesale power supplies through bilateral contracts,<br />
such as public power systems and large industrials, would find it difficult to<br />
obtain reasonably priced contracts.<br />
45<br />
One such auction is the New Jersey Basic Generation Service or BGS auction. Contracts for<br />
residential and small business customers last three years with one-third of load procured each<br />
year, and commercial and industrial customers are supplied in one-year contracts. A full description<br />
of the BGS auction regime can be found at: State of New Jersey, Board of <strong>Public</strong><br />
Utilities, BGS Auction, http://www.state.nj.us/bpu/divisions/energy/bgs.html<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 15
Changes in state policies that would allow their incumbent LSEs to purchase<br />
or build generation facilities or enter into longer-term (e.g., 5-15 year) power<br />
supply arrangements to provide SOS to their retail customers would impose<br />
needed discipline on the wholesale market.<br />
An essential component of APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> is a strong<br />
recommendation that state public service commissions establish competitive<br />
resource procurement processes to develop diversified resource portfolios for<br />
incumbent IOU LSEs that no longer have the obligation to serve customers,<br />
with a significant portion of their power supplies being obtained under<br />
longer-term contracts or owned-generation arrangements. These measures<br />
could provide much needed price discipline in RTO-run centralized markets,<br />
as well as a steady revenue stream to support construction of new generation<br />
resources and investment in demand response technologies. 46 Such a statelevel<br />
procurement process is described in greater detail in Section X<br />
(Resource Adequacy and <strong>Plan</strong>ning).<br />
APPA recognizes that state commissions may have some reluctance to require<br />
the LSEs they regulate to lock-in long-term prices, for fear that prices will<br />
subsequently decline, leaving LSEs on the “wrong side” of current market<br />
prices. Long-term contracts entered into by many utilities in the 1970s and<br />
1980s were later found to be “above-market,” causing the payment of stranded<br />
costs following state-level deregulation. 47 The <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong><br />
contains two recommendations to hedge the potential long-term contract risk.<br />
The first is to procure a portfolio with a blend of long-, medium- and shortterm<br />
resource contracts to minimize the price risk associated with any one<br />
resource arrangement. Longer-term contracts could be targeted to new<br />
generation units and resource arrangements that require more revenue<br />
certainty to secure financing and ensure a reasonable cost of capital, while<br />
medium- and short- term arrangements could be targeted to older, largely<br />
46<br />
A 2008 report by the Maryland <strong>Public</strong> Service Commission finds that long-term power purchase<br />
agreements (PPAs) would encourage needed generation and lower wholesale market<br />
costs. Final Report of the <strong>Public</strong> Service Commission of Maryland to the Maryland General<br />
Assembly Options for Re-Regulation and New Generation, December 2008, p. 28, http://webapp.psc.state.md.us/Intranet/sitesearch/MD%20PSC%20SB400%20Final%20Report%20to<br />
%20the%20MD%20General%20Assembly.pdf<br />
In a Connecticut proceeding, Levitan & Associates found that “[n]ew generation in Connecticut<br />
anchored under a long-term contract should thus help put downward pressure on energy<br />
prices in Connecticut,” and that “[f]uel diversity objectives in New England could be promoted<br />
through long term contracts.” Comments Of Levitan & Associates, Inc., DPUC Development<br />
and Review of Standard Service and Supplier of Last Resort Service Docket<br />
06-01-08PH01 Jan. 30, 2007, pp. 4 and 11, http://www.dpuc.state.ct.us/dockhist.nsf/<br />
f068a53a31082a558525664e00498f40/3bf2ed4f4da8cfe3852573f000640cf6/$FILE/LAI%20C<br />
omments%2030Jan07.pdf<br />
47<br />
Electric Utilities: Deregulation and Stranded Costs, Congressional Budget Office, October<br />
1998, http://www.cbo.gov/ftpdocs/9xx/doc976/stranded.pdf. Of course, in many cases the<br />
assets in question were eventually found to be “in the market” rather than “above-market.”<br />
16 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
depreciated units and other resources that do not demand high up-front<br />
capital commitments. The second recommendation, discussed below, is to<br />
allow incumbent utilities to construct their own power plants on a going<br />
forward basis if there are insufficient or unacceptable options put forth by<br />
third-party generators.<br />
As part of such an improved SOS resource procurement process, retail access<br />
states should allow their incumbent IOU LSEs to consider “self-builds” and<br />
“self-provision” of demand response as resource options. In many retail choice<br />
states, incumbent LSEs are currently prohibited from building new<br />
generation (except perhaps through an unregulated affiliate), even though<br />
they still bear responsibility for providing SOS service. The availability of selfbuild<br />
options brings additional competitive discipline to bear on third-party<br />
suppliers submitting generation supply offers in power supply procurements.<br />
While concerns about pending generation supply shortages that were<br />
prevalent in 2006 and 2007 have been mitigated by increased demand<br />
response and recession-induced load decreases, 48 such state-implemented<br />
measures to provide additional sources of supply when needed would also<br />
reduce potential for tighter supply conditions in the future that could drive<br />
up prices, 49 especially those resulting from the potential closure of coal plants<br />
as will be discussed later in this document.<br />
Recent experience with state legislative and regulatory actions to procure new<br />
generation resources outside of the centralized capacity markets, and<br />
encourage the development of cleaner and more efficient generation,<br />
illustrate potential difficulties for undertaking such efforts. These actions,<br />
while beneficial to the states’ interests in protecting consumers, improving<br />
reliability and reducing power plant emissions, also adversely affect the profits<br />
of incumbent power plant owners. As a result, such merchant generators have<br />
successfully exerted pressure on the RTOs and FERC to change the rules<br />
governing the capacity markets to prevent such state measures in the future.<br />
One of the earlier undertakings began with Connecticut’s signing of longterm<br />
contracts with a number of new peaking units in accordance with<br />
48<br />
These changes can be illustrated by the findings of the Long-Term Reliability Assessment<br />
(LTRA) issued annually by the North <strong>American</strong> Electric Reliability Corporation (NERC). In<br />
the 2007 LTRA, NERC stated that: “Long-term capacity margins are still inadequate.” In the<br />
2010 LRTA, released in October 2010, NERC concluded that “NERC Regions and subregions<br />
have sufficient plans for capacity to meet customer demand over the next ten years.”<br />
http://www.nerc.com/page.phpcid=4|61<br />
49<br />
A 2009 Wall Street Journal article notes: “Some wonder whether the deregulated markets of<br />
the Eastern U.S., Midwest, Texas and California will be especially hard hit if demand comes<br />
roaring back. That’s because utilities in these markets no longer are required to build new resources.<br />
It’s left up to the power generators to determine when the market conditions are<br />
ripe.” Rebecca Smith, “Electricity Prices Plummet,” The Wall Street Journal, August 12, 2009,<br />
http://online.wsj.com/article/SB125003563550224269.html, Subscription required.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 17
legislation passed in 2005 and 2007 aimed at lowering congestion costs,<br />
spurring new generation, demand response and renewable energy. 50 When<br />
ISO New England’s Forward Capacity <strong>Market</strong> (FCM) auctions began in early<br />
2008, Connecticut bid contracted units into the auction as “price takers.”<br />
More recently, in early 2011, Governor Christie of New Jersey signed<br />
legislation and the Maryland <strong>Public</strong> Service Commission issued a draft RFP<br />
for the procurement of new generation resources through long-term<br />
contracts with the distribution utilities. 51 In both cases, the states were<br />
responding to the absence of new, efficient and cleaner generation resulting<br />
from PJM’s RPM and concerns about future reliability. The contracted-for<br />
capacity would then be bid into the capacity markets at zero or a very low<br />
price to ensure that it would clear the auction, with the secondary benefit of a<br />
lower capacity price for all capacity that cleared the auction.<br />
In New England, the capacity price has reached the floor price in the last<br />
auction and the lower bound of the price collar in the prior three auctions. 52<br />
While it is not certain that the Connecticut resource bids directly caused the<br />
low capacity price, which may have resulted more from the large quantity of<br />
demand response bids, the coincidence of these state-procured resources and<br />
the low price spurred a complaint with FERC by the merchant generator<br />
association (the New England <strong>Power</strong> Generators <strong>Association</strong> or “NEPGA”).<br />
Similarly, in response to concerns over a possible future reduction in capacity<br />
market revenue from the New Jersey and Maryland actions, 53 the PJM <strong>Power</strong><br />
Providers or “P3” filed a complaint with FERC. In response to these<br />
complaints, both RTOs proposed changes in their capacity markets to prevent<br />
the price-lowering effects of such separately procured resources.<br />
In April 2011, FERC issued its orders in both dockets. 54<br />
At the core of each<br />
50<br />
<strong>Public</strong> Act 05-01, An Act Concerning Energy Independence, July 2005,<br />
http://www.cga.ct.gov/2005/ACT/Pa/pdf/2005PA-00001-R00HB-07501SS1-PA.pdf; and <strong>Public</strong><br />
Act 07-242, An Act Concerning Electricity and Energy Efficiency, June 2007,<br />
http://www.cga.ct.gov/2007/ACT/PA/2007PA-00242-R00HB-07432-PA.htm<br />
51<br />
New Jersey P.L.2011, Chapter 9, Senate, No. 2381, §§1,3,4 - C.48:3-98.2 to 48:3-98.4 §5 -<br />
C.48:3-60.1, http://www.njleg.state.nj.us/2010/Bills/AL11/9_.PDF; Notice Of Comment Period<br />
On Request For Proposals For New Generating Facilities, Maryland <strong>Public</strong> Service Commission,<br />
December 29, 2010,<br />
http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfmServer-<br />
FilePath=C:\Casenum\9200-9299\9214\\34.pdf.<br />
52<br />
FCM Calendars and Auction Results, http://www.isone.com/markets/othrmkts_data/fcm/cal_results/index.html<br />
53<br />
Monitoring Analytics conducted analyses of the New Jersey legislation and Maryland PSC<br />
draft RFP showing a reduction in capacity revenues of $3 billion dollars per year ($2 billion<br />
from New Jersey and $1 billion from Maryland).<br />
http://www.monitoringanalytics.com/reports/Reports/2011/NJ_Assembly_3442_Impact_on_PJM_Capacity_<strong>Market</strong>.pdf;<br />
and http://www.monitoringanalytics.com/reports/Reports/2011/IMM_Comments_to_MDPSC_Case_No_9214_20110128.pdf<br />
18 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
APPA is most concerned by the<br />
Commission’s holdings in these two<br />
orders, and in particular its seeming<br />
lack of recognition or respect for the<br />
states’ traditional role in assuring<br />
that retail electric service is both<br />
reliable and reasonably priced.<br />
APPA has in the past called for a<br />
respectful dialogue on these issues,<br />
and renews that call here.<br />
order are rule changes that will impose minimum prices on offers from new<br />
natural gas generators. As a result, new natural gas-fired resources procured<br />
by either the state or another LSE, such as a public power utility or a<br />
cooperative, would be likely to have their low-bids replaced with a higher offer<br />
price, making it very difficult for such resources to clear the market. These<br />
rule changes are a significant threat to both LSE self-supply and to statesponsored<br />
power procurements. Following the PJM decision, Lee Solomon,<br />
President of the New Jersey Board of <strong>Public</strong> Utilities, stated that FERC’s order<br />
“does not address the failure of the PJM market to deliver new capacity which<br />
is desperately needed to reduce New Jersey’s energy prices, and to replace<br />
aging, dirty, and inefficient generation facilities.” President Solomon also<br />
stated that the BPU plans to pursue “options available to us that are outside of<br />
FERC’s jurisdiction,” concluding that he does “not believe that New Jersey<br />
forfeited its sovereignty when PJM became the regional transmission<br />
operator.” 55<br />
APPA is most concerned by the Commission’s holdings in these two orders,<br />
and in particular its seeming lack of recognition or respect for the states’<br />
traditional role in assuring that retail electric service is both reliable and<br />
reasonably priced. APPA has in the past called for a respectful dialogue on<br />
these issues, and renews that call here.<br />
54<br />
Order Accepting Proposed Tariff Revisions, Subject To Conditions, And Addressing Related<br />
Complaint, 135 FERC 61,022 (April 12, 2011),<br />
http://elibrary.ferc.gov/idmws/common/OpenNat.aspfileID=12617771; and Order On<br />
Paper Hearing And Order On Rehearing, 135 FERC 61,029 (April 13, 2011), http://elibrary.ferc.gov/idmws/File_list.aspdocument_id=13909713<br />
55<br />
News Release, New Jersey Board of <strong>Public</strong> Utilities, April 13, 2011,<br />
http://www.state.nj.us/bpu/newsroom/news/pdf/20110413a.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 19
20 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
V. Bilateral Contracts<br />
O<br />
ne of the core features of APPA’s RTO market redesign proposal is<br />
that LSEs would serve their loads with a combination of owned<br />
generation/demand-side resources and generation/demand-side<br />
resources obtained under longer- term bilateral contracts. <strong>Market</strong><br />
participants (wholesale buyers and sellers) could enter into any<br />
contractual arrangement acceptable to both parties, subject to state and<br />
RTO requirements governing the resource portfolio of each LSE and the<br />
eligibility of the seller for market-based rate authority (as discussed<br />
below). APPA is not in this <strong>Plan</strong> recommending any requirements for LSEs<br />
to enter into bilateral contracts, nor does this plan place any restrictions<br />
on the amount or percentage of power purchased through the<br />
optimization market. Rather, the reforms proposed here are likely to both<br />
incent and remove barriers to bilateral contracting, and reduce potential<br />
for excess earnings in the current market structure.<br />
An important component of the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> is the phase-out<br />
of existing locational capacity markets. Payments established under<br />
auctions for future delivery years would still be honored for their terms,<br />
but going forward past that time, generation owners and demand response<br />
providers would need to make contractual arrangements to sell their<br />
resources, or sell their resources into the RTO’s optimization market<br />
without the financial backstop of separate capacity market payments.<br />
To support the financing of new power plants, ownership arrangements or<br />
bilateral contracts of at least 10 to 15 years in length would likely be<br />
needed. Such arrangements and contracts would also provide needed<br />
price stability for LSEs and their retail customers. APPA, however, is not in<br />
this proposal specifying minimum or specific contract lengths and terms.<br />
Instead we recommend, and expect, that each LSE would likely develop a<br />
portfolio of diverse resources of varying lengths and terms. The<br />
<strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> is intended to improve the overall market<br />
environment by making a significant number of long-term resource<br />
arrangements of 10 years or longer readily available to buyers and sellers.<br />
The RTO’s optimization market would allow for residual optimization of<br />
LSE energy supply arrangements and balancing in real-time.<br />
APPA originally proposed these market structure changes in response to<br />
reports from APPA members and large end-use customers that in RTO<br />
markets, long-term, reasonably-priced bilateral contracts were difficult to<br />
arrange (especially full-requirements contracts). 56 Many buyers reported<br />
56<br />
Communications with APPA members, and testimony summarized in “Executives describe<br />
real-world problems with RTOs,” <strong>Public</strong> <strong>Power</strong> Daily, Feb. 29, 2008,<br />
http://publicpower.org/newsletters/ppdailydetail.cfmItemNumber=21269&sn.ItemNumber=0<br />
(Login required)<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 21
that the high prices sellers could obtain in the bid-based RTO-run spot<br />
markets discouraged the signing of long-term contracts, or resulted in<br />
contract offers directly linked to spot market prices. 57 Studies of bilateral<br />
markets in RTO regions have shown that such RTO markets pose<br />
impediments to reasonably priced long-term bilateral contracting. 58<br />
APPA now believes that there is an additional reason to foster the signing<br />
of at least some longer-term generation contracts that can support the<br />
development of new resources—the need to revamp the nation’s<br />
generation fleet over the coming years to address environmental concerns.<br />
The Environmental Protection Agency (“EPA”) is currently conducting a<br />
series of rulemakings to regulate emissions of greenhouse gases from large<br />
stationary sources, including power plants. In addition, the EPA is in the<br />
middle of a substantial number of other rulemakings, dealing with coal<br />
ash, mercury, and other hazardous air pollutants, criteria pollutants<br />
(smog), water use in once-through cooling systems, and a number of other<br />
items.<br />
As these various rules go into effect, their cumulative effect will likely<br />
make it uneconomic for generators to continue to operate a substantial<br />
number of existing coal-fired power plants. Estimates of coal plant closures<br />
range from 30 to 70 gigawatts (GW) of coal generation within the next ten<br />
years, with most estimates trending towards the higher end of this range. 59<br />
A substantial portion of that retiring capacity will have to be replaced,<br />
mostly with natural -gas- fired units. And coal-fired power plants constitute<br />
a very substantial portion of the generation fleets of a number of RTOs.<br />
57<br />
For example, Walter Brockway of Alcoa testified before FERC that: “We found no supplier willing to discuss<br />
supplying us with anything other than electricity priced to reflect peak load generation, as well as<br />
placing on us all the risk of trans-mission congestion.” Technical Conference to Examine the State of<br />
Competition in Wholesale <strong>Power</strong> <strong>Market</strong>s, Docket AD07-7-000, May 8, 2007,<br />
http://www.ferc.gov/EventCalendar/Files/20070508083948-Brockway,%20Alcoa.pdf.<br />
58<br />
E. Hausman, R. Hornby and A. Smith, Bilateral Contracting in RTO <strong>Market</strong>s, Synapse Energy Economics,<br />
April 2008, http://publicpower.org/files/PDFs/EMRISynapseBilateralsReport2008.pdf; also, see the<br />
discussion of fixed-price contracts and supplier behavior in Frank A. Wolak and Shaun D. McRae,<br />
Merger Analysis in Restructured Electricity Supply Industries: The Proposed PSEG and Exelon Merger,<br />
November 2007, ftp://zia.stanford.edu/pub/papers/pseg_exelon_merger.pdf<br />
59<br />
Studies of projected coal plant closures have been undertaken by: The North <strong>American</strong> Electric<br />
Reliability Corporation (10 - 35 GW of coal and 40 - 70 GW of all capacity by 2018), 2010<br />
Special Reliability Scenario Assessment, October, 2010, Table IV-6,<br />
http://www.nerc.com/files/EPA_Scenario_Final.pdf; Credit Suisse Equity Research (60 GW<br />
of coal capacity between 2013 and 2017), Growth From Subtraction: Impact of EPA Rules on<br />
<strong>Power</strong> <strong>Market</strong>s, September 23, 2010, http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf;<br />
The Brattle Group (50 – 66 GW of coal capacity by 2020), Potential Coal <strong>Plan</strong>t Retirements<br />
Under Emerging Environmental Regulations, December 8, 2010,<br />
http://www.brattle.com/_documents/UploadLibrary/Upload898.pdf, and FBR Capital (30 –<br />
70 GW in the next few years), EPA regs may shut 70,000 MW of U.S. coal plants: FBR, Reuters,<br />
December 13, 2010 http://www.reuters.com/article/2010/12/13/us-utilities-epa-coal-idUS-<br />
TRE6BC3JN20101213<br />
22 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
In addition to the financial incentives<br />
for owners of existing merchant<br />
generation to constrain the capacity<br />
supply, many current RTO market<br />
structures simply cannot support<br />
the development of new resources<br />
by newer market entrants.<br />
Unlike generation owned by a vertically- integrated utility, the future<br />
earnings of merchant generation owners would be higher for their<br />
remaining existing plants if a portion of generation is shut down and the<br />
supply of power becomes constrained. One likely scenario is for merchant<br />
generators to strategically close the plants that are the most costly to<br />
retrofit while allowing the remaining plants, especially nuclear and lower<br />
emission coal plants, to benefit from the resulting higher prices. 60 Several<br />
recent analyses have found that the closure of coal plants is in fact likely to<br />
be greater for merchant units. The Brattle Group found that most of the<br />
coal plants likely to retire will be merchant units, accounting for 64 to 76<br />
percent of merchant coal capacity compared to 1 to 4 percent of regulated<br />
coal, whose regulated owners would be much more likely to retrofit the<br />
plants. 61<br />
APPA therefore believes the industry will need to make substantial<br />
investments in new gas-fired and renewable generation resources as these<br />
coal-fired power plants leave the fleet. In addition to the financial<br />
incentives for owners of existing merchant generation to constrain the<br />
capacity supply, many current RTO market structures simply cannot<br />
support the development of new resources by newer market entrants.<br />
Such generation projects take time to construct, and they generally<br />
require secure financing, anchored by long-term (ten-year or more) power<br />
purchase agreements or other “take-away” commitments. 62 This problem<br />
60<br />
For example, Credit Suisse notes that “the retrofit / closure decision will not occur in a vacuum<br />
such that plants ‘on the bubble’ for investment could be attractively economic as other<br />
plants are pulled from the market.” Credit Suisse Equity Research, p. 36. Similarly, Fitch Ratings<br />
concluded that: “Merchant generation that does not rely on coal (or coal-fired generation<br />
that is already highly controlled) could increase its profitability if a significant portion of<br />
coal-fired generation in the same region is retired and heat rates rise in the region due to<br />
stringent enforcement of new EPA rules.” Time to Retire US Coal <strong>Plan</strong>ts in Environmental<br />
Crosshairs, FitchRatings, February 2011, p. 2 http://www.fitchratings.com/creditdesk/reports/report_frame.cfmrpt_id=604365<br />
61<br />
The Brattle Group, p. 6<br />
62<br />
In comments submitted by <strong>Competitive</strong> <strong>Power</strong> Ventures (CPV) to the Maryland <strong>Public</strong> Service<br />
Commission on RPM, CPV attached several letters from lenders asserting that long-term<br />
contracts are critical for obtaining financing for new generation projects. For example, the<br />
Bank of Tokyo-Mitsubishi wrote that it “favor[s] the projects which operate in markets with<br />
transparent and stable regulatory regimes and projects which benefit from long-term fixedprice<br />
power purchase agreements with investment grade counterparties.” Comments of CPV<br />
Maryland, LLC, In the Matter of the Reliability Pricing Model And the 2013/2014 Delivery<br />
Base Year Residual Auction Results, Maryland <strong>Public</strong> Service Commission, Administrative<br />
Docket PC22, October 1, 2010, Attachment B, http://webapp.psc.state.md.us/Intranet/AdminDocket/NewIndex3_VOpenFile.cfmServerFilePath=C%3A%5CAdminDocket%5C<strong>Public</strong>Conferences%5CPC22%5C35%2Epdf<br />
63<br />
For a detailed discussion of the greater adverse impact on reliability and prices in RTO regions<br />
resulting from EPA regulations, see Issue Brief: Why New CO2 Regulations Could Produce<br />
Windfall Profits and Unproductive Costs for Consumers, <strong>American</strong> <strong>Public</strong> <strong>Power</strong><br />
<strong>Association</strong>, March 2011, http://www.publicpower.org/files/PDFs/IssueBriefWindfallProfitsandEPARegsMarch2011.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 23
will be especially pronounced in RTOs with restructured retail markets. 63<br />
APPA does not expect that increased reliance on longer-term bilateral<br />
contracts and owned generation will immediately produce lower prices. It<br />
is, however, likely to produce more stable and reasonable prices in the<br />
long run. Shorter-term power supply contracts of three years or less, such<br />
as those procured to provide SOS, frequently include generation prices<br />
above the spot prices set in RTO markets, in part due to the inclusion of<br />
risk premiums. 64 Diversified LSE resource portfolios that include longerterm<br />
contracts of 10, 20 or more years may still entail some risk premium<br />
because suppliers would be absorbing the risk of reduced demand. But<br />
such premiums are likely to be mitigated by APPA’s proposed price<br />
formation mechanism for the optimization market. This market structure<br />
should better discipline spot prices, which in turn should discipline<br />
bilateral contract prices formed through responses to LSE requests for<br />
proposals, where suppliers of generation and demand response must<br />
compete directly with each other, as well as with the prospect of LSEowned<br />
projects. Any risk premiums that suppliers do require are likely to<br />
be exceeded by the benefits of greater price stability.<br />
There is not sufficient data to ascertain the current status of bilateral<br />
contracting in RTO regions. For example, PJM’s State of the <strong>Market</strong><br />
reports provide data on the percentage of power purchased through<br />
bilateral contracts, self-supply and spot markets. In the 2010 State of the<br />
<strong>Market</strong> Report, these data show that 11.8 percent of the power purchased<br />
in the real-time and 4.9 percent in the day-ahead market was sold through<br />
bilateral contracts, a decrease of 1.1 percentage points from the prior year<br />
for the real-time market, and no change in the day-ahead market. 65 But<br />
PJM does not break down these data according to the length of the<br />
contract or the pricing terms. Theoretically, a one-week agreement to sell<br />
power at a price indexed directly to prices set in PJM’s spot market would<br />
be counted as a bilateral contract.<br />
64<br />
Testimony of Kenneth Rose, Ph.D., Independent Consultant, before the Pennsylvania <strong>Public</strong><br />
Utility Commission, November 6, 2008, http://www.puc.state.pa.us/electric/pdf/EnBanc-<br />
WEM/Ttmy-Kenneth_Rose110608.pdf , p. 8 – 11. A presentation by Pennsylvania PUC Chairman<br />
James H. Cawley noted that PECO’s default price “includes a risk premium to account<br />
for future load level uncertainty.” Philadelphia Business Journal, 2010 Energy Summit, October<br />
28, 2010, http://www.puc.state.pa.us/electric/pdf/PPT-PBJ_Presentation102810-<br />
Cawley.pdf<br />
65<br />
2010 State of the <strong>Market</strong> Report for PJM, Section 2, Monitoring Analytics, March 20, 2011, p.<br />
106-107, http://www.monitoringanalytics.com/reports/PJM_State_of_the_<strong>Market</strong>/2010/2010-<br />
som-pjm-volume2-sec2.pdf. These data are reported at the level of the parent company such<br />
that bilateral sales between generation-owing and load- serving regulated utility affiliates would<br />
be reported as self-supply and not as a bilateral contract. In the State of the <strong>Market</strong> reports for<br />
2008 and earlier, these data were also reported for the billing company which reported that<br />
about 96 percent of real-time sales were made through bilateral contracts.<br />
24 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
No data on bilateral contracts was found in the ISO New England and the<br />
Midwest ISO State of the <strong>Market</strong> reports. 66 New York ISO reports only on<br />
“physical bilateral contracts,” which involve settlements with the New York<br />
ISO for transmission charges and between the parties privately for the<br />
commodity prices and do not include bilateral contracts that are settled<br />
privately. Physical bilateral contracts comprised about 50 percent of the<br />
day-ahead load in New York City and Long Island, 40 percent in East<br />
upstate, and 60 percent in West upstate in 2008, the last year for which<br />
these data are available. 67 As with PJM, there is no information provided<br />
on length or pricing terms.<br />
Moreover, the RTO definition of a bilateral contract does not require that<br />
a contract be tied to associated capacity, such as a specific generating unit.<br />
Some of the bilateral contracts are sales of power to utilities for the<br />
provision of standard offer service load, whose prices are often based on<br />
RTO spot market prices. These SOS contracts need not be tied to specific<br />
generating units, and even if the supplier is delivering electrons from its<br />
own generating assets, prices are still tied to the spot markets, and not the<br />
costs of producing electricity from such units. 68<br />
In many other cases, the bilateral contracts used in RTO regions are<br />
standardized and the power product choices do not include capacity<br />
obligations or other provisions that would support new generation<br />
infrastructure. For example, the EEI/NEMA Master Agreement used in<br />
many eastern RTOs contains standardized language for product<br />
definitions, credit requirements and buyer/seller obligations. 69 A typical<br />
contract will specify a delivery point, price, quantity and time frame (for<br />
example, “20 MW delivered at [a selected trading hub] during on-peak<br />
hours in calendar year 2008”). These contracts also include “liquidated<br />
damages” or other liability provisions outlining financial responsibility for<br />
66<br />
An e-mail from ISO New England Customer Services, Dec. 24, 2008, in response to an APPA inquiry<br />
about bilateral contracting data states that “we do not report the bilateral contract or spot<br />
market activities.” No response was received from MISO, although the MISO 2009 State of the<br />
<strong>Market</strong> Report notes that the small portion of capacity clearing the Voluntary Capacity <strong>Market</strong><br />
indicates that “most LSEs’ capacity needs [are] satisfied through owned capacity or bilateral<br />
purchases.” (p. 24), http://www.midwestiso.org/publish/Document/55f670_12a43afcc88_-<br />
7f610a48324a/2009%20State%20of%20the%20<strong>Market</strong>%20Report.pdfaction=download&_pro<br />
perty=Attachment<br />
67<br />
2008 State of the <strong>Market</strong> Report, New York ISO, p. 68-69 http://www.nyiso.com/public/webdocs/documents/market_advisor_reports/2008/NYISO_2008_SOM_Final_9-2-09.pdf<br />
(The<br />
2009 and 2010 State of the <strong>Market</strong> Reports contain less detail and do not provide separate bilateral<br />
load data.)<br />
68<br />
For example, see Letter from Constellation Energy to President Miller and Speaker Busch, May<br />
31, 2006, http://www.sec.gov/Archives/edgar/data/1004440/000110465906038686/a06-<br />
12885_1ex99d1.html.<br />
69<br />
The provisions of the EEI/NEMA Master Contract are available at http://www.eei.org/industry_issues/legal_and_business_practices/master_contract.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 25
failure to perform under the terms of the contract. Under such<br />
agreements, a failure to supply power is not a breach of the agreement,<br />
but merely triggers the obligation on the part of the buyer to “cover” by<br />
obtaining replacement supplies at whatever price the buyer can obtain in<br />
the market at that time, with the seller paying the difference between the<br />
contract and market price. Such contracts may work well for financial<br />
parties interested in trading contracts, but are less than ideal for LSEs<br />
attempting to assemble a portfolio of power supply resources that can in<br />
fact be used to serve load. 70 Under APPA’s proposal, a truly vibrant<br />
bilateral market would rely less on standardized contracts developed<br />
primarily for trading purposes, and more on individually negotiated<br />
agreements sufficient to support the development of new generation and<br />
demand-side resources.<br />
In October 2008, FERC required each RTO to dedicate a portion of its<br />
web site for market participants to post offers to buy or sell power on a<br />
long-term basis, concluding “that greater transparency from a bulletin<br />
board for long-term power sales will benefit long-term contracting.” 71 A<br />
multiple-RTO bulletin board was set up in response, but appears to have<br />
been of limited use. Periodic visits since February 2010 show no more than<br />
four contract offers posted at a given time. All but one of the contracts<br />
displayed have been just one year in length. On September 21, 2010, only<br />
one contract offer was posted -- for the sale of 2 MW of capacity for a oneyear<br />
time frame. No offers were posted on the bulletin board, when it was<br />
again visited on April 15, 2011. It is not clear why this bulletin board has<br />
not been more widely used, but the creation of a more viable market for<br />
bilateral contracting will require much more substantive market reforms<br />
than an on-line bulletin board.<br />
70<br />
Many “net buyer” APPA members have found the standard EEI/NEMA contract terms and options<br />
unsuitable for their own power procurement needs. APPA therefore developed a package<br />
of modifications to that contract (suitable for use by such buyers), available upon request.<br />
71<br />
Wholesale Competition in Regions with Organized Electric <strong>Market</strong>s, Order No. 719, 125<br />
FERC 61,071, 73 Fed. Reg. 64,100 (October 28, 2008), p.165<br />
26 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
VI. <strong>Market</strong> <strong>Power</strong><br />
W<br />
ithout new generation entry or a significant expansion in demand<br />
response and efficiency investments, generators may still have market<br />
power in the long-term bilateral contract markets, just as they now do in<br />
spot and locational capacity markets. This market power cannot be wished<br />
away. Generators are likely to attempt to exercise market power even if APPA’s<br />
<strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> is implemented, particularly in the early days of new<br />
market operations. Still, there are a number of reasons to believe that market<br />
power may become less of a problem (at least in the long run) and that<br />
markets would be more competitive under APPA’s <strong>Plan</strong>:<br />
• In current Day Two RTO markets, suppliers interact with each other<br />
frequently, since the RTO auctions clear on very short time intervals.<br />
This repeated interaction allows generators to observe the strategies of<br />
other bidders and respond in kind, encouraging coordinated bidding<br />
strategies and even tacit collusion. 72 A recent study found that the<br />
entities bidding generation units frequently are not the owners, and can<br />
change their contractual control of the units, possibly gaining important<br />
knowledge regarding their competitors’ units. 73 Bilateral contracting<br />
processes, especially ones conducted under formal requests for proposals<br />
(RFPs) subject to public scrutiny, such as state-supervised procurements,<br />
would be less likely to be subject to such ongoing coordination.<br />
• Bilateral contracting provides a greater opportunity for customers and<br />
suppliers to negotiate “customized” products to meet the supplier’s and<br />
customer’s particular needs, rather than being force-fit into a<br />
standardized form agreement. Capacity prices arranged through<br />
contracts negotiated under RFP procedures could better reflect the fixed<br />
costs attributable to different resources, whereas centralized capacity<br />
markets pay the same price to all resources regardless of whether they<br />
are a new resource facing a tight financing market, an existing and<br />
largely depreciated facility or a demand response offer with limited upfront<br />
investments required. Contract lengths could also be tailored to the<br />
type of resource – shorter-term for energy efficiency measures or longerterm<br />
for new capital-intensive generation projects.<br />
• Bilateral contracting affords the customer the ability to select among<br />
different counter-party suppliers based on creditworthiness and other<br />
non-price factors relevant to performance over the long term.<br />
• Compared to transactions in a spot or short-term market, longer-term<br />
72<br />
Experiments at Carnegie Mellon and Cornell “show that hourly auction markets are ideally<br />
designed to teach participants to manipulate the market to raise profit.” Lester Lave, Jay Apt,<br />
and Seth Blumsack, Deregulation/Restructuring, Where Should We Go from Here Carnegie<br />
Mellon Electricity Industry Center, 2007, p. 14, http://wpweb2.tepper.cmu.edu/ceic/papers/ceic-07-07.asp<br />
73<br />
John Kwoka, Finnegan Professor of Economics , The Effect of Cross-Control on Bidding Behavior<br />
and Prices in Electricity Auction <strong>Market</strong>s, Northeastern University, September 2010,<br />
http://www.publicpower.org/files/PDFs/kwokacrosscontrol.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 27
ilateral arrangements provide revenue stability that makes it possible for<br />
potential suppliers to finance capital-intensive generation projects at<br />
more reasonable capital costs, reducing barriers to entry into the<br />
generation market. 74<br />
• Within a day-ahead or hour-ahead time frame, many suppliers have<br />
operational constraints (unit commitment, ramping, etc.) that keep<br />
them from being active bidders in RTO-run spot markets. Since there is<br />
more operational flexibility built into a long-term bilateral contract, a<br />
given buyer could have more potential counterparties.<br />
• Because the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> would provide the transmission<br />
access and financial rights necessary for LSEs to have more and better<br />
power supply choices, including self-build and ownership of generation if<br />
they receive non-competitive supply offers, LSEs should in the long run<br />
have fewer problems with market power being exercised in the bilateral<br />
market.<br />
To incent participation in bilateral markets, APPA is also proposing that<br />
generators in each RTO region that pass the FERC’s relevant market-based<br />
rate screens should be permitted to sell at market-based rates in bilateral<br />
forward markets. The screens used to determine market power should<br />
include, at a minimum, the existing measures used by FERC and individual<br />
RTO market monitors, such as PJM’s “three pivotal supplier” test. However, to<br />
guard against the exercise of generation market power, APPA believes that<br />
FERC should separately assess market-based rate applicants’ generation<br />
market power in long-term power supply product markets. To the extent that<br />
applicants do not pass such long-term market power screens, their marketbased<br />
rate authority would be appropriately conditioned or, if merited,<br />
revoked.<br />
FERC must also ensure that RTO <strong>Market</strong> Monitors (“MMs”) are truly<br />
independent and have all of the resources necessary to perform their<br />
functions. As APPA recommended in Consumers in Peril, RTO MMs should<br />
have the full cooperation of market participants in data gathering, including<br />
access to company-specific financial information and generating unit cost and<br />
operating data, as well as sufficient resources to carry out their duties. RTO<br />
MMs should also monitor bilateral contract markets, and act on complaints<br />
regarding anticompetitive behavior by sellers or buyers in those markets.<br />
74<br />
This is especially relevant in light of the recent economic downturn. A 2009 study commissioned<br />
for the Maryland <strong>Public</strong> Service Commission found that: “The breakdown in the capital<br />
markets and recent credit implosion make it more difficult for new merchant resources to<br />
attract financing on competitive terms absent long-term contracts with creditworthy counterparties.”<br />
Financial Risk Analysis of the Return to Rate Base Regulation , Levitan & Associates,<br />
Inc. & Kaye Scholer LLP, March 11, 2009, http://webapp.psc.state.md.us/Intranet/sitesearch/Kaye%20Scholer_Supplement%20to%20Final%20Report_Financial%20Risk%20Anal<br />
ysis%20of%20the%20Return%20to%20Rate%20Base%20Regulation.pdf<br />
28 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
Moreover, MM State of the <strong>Market</strong> reports should provide much clearer and<br />
detailed information on bilateral contracts, indicating the length of such<br />
contracts, whether they are backed by the capacity of specific generating units<br />
or other appropriate arrangements, and whether prices are fixed or indexed<br />
to RTO prices.<br />
APPA, however, remains quite concerned that due to the high concentration<br />
in wholesale power supply markets, exercise of generation market power in<br />
bilateral markets could indeed occur even if APPA’s proposed reforms are<br />
implemented. For this reason, APPA proposes that FERC conduct a review of<br />
regional bilateral wholesale markets three years after implementation of<br />
APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>, to investigate whether market power<br />
remains a substantial concern. If the commission finds that market power<br />
exercise is a problem in bilateral markets in RTO regions, appropriate<br />
modifications should be made to FERC’s market-based rate regulations and<br />
RTO market rules to address this problem.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 29
VII. Residual Short-Term and Imbalance Services:<br />
The Optimization <strong>Market</strong><br />
B<br />
ecause generator availability and customer demand cannot be<br />
perfectly predicted, and electricity cannot (yet) be stored<br />
economically in sufficiently large quantities, APPA’s proposal includes<br />
an RTO-operated residual “optimization” market. This market would allow<br />
for the co-optimization of offers by generators to sell excess energy and<br />
ancillary services, and for LSEs to obtain economy energy and clear<br />
imbalances. The optimization market also would provides an opportunity for<br />
the sale of variable generation 75 not committed under bilateral agreements<br />
and allows for the purchase of replacement power for variable generation not<br />
available at a given time.<br />
APPA believes it is not in the interest of either buyers or sellers to place set<br />
limits on the percentage of load that can be met through the optimization<br />
market. Such limits reduce needed flexibility for LSEs, including their ability<br />
to purchase power from variable generation resources, and restrict the<br />
flexibility of generators (especially variable generators) as well. APPA’s<br />
proposed RTO-run optimization market is designed to minimize the size of<br />
the spot market and encourage bilateral contracting for load not served by<br />
owned resources to the maximum extent possible without unduly restricting<br />
market participant options. Key design features of the optimization market<br />
include:<br />
1) Generator offers to sell into the optimization market would be<br />
limited to no more than their short-run marginal costs (SRMC). The<br />
SRMC includes only those costs that vary with the level of output, primarily<br />
fuels and operations, maintenance and administrative costs that vary with<br />
output. (For example, periodic inspection, replacement and repair of system<br />
components would be included because such maintenance depends upon the<br />
level of output. 76 ) Opportunity costs would not be included in the calculation<br />
of the SRMC 77 , including for ancillary services, which will be co-optimized<br />
with energy dispatch.<br />
75<br />
By “variable generation” APPA means resources that have little control over when they generate<br />
due to their dependence on renewable “fuels,” e.g., wind and solar resources.<br />
76<br />
Serkan Bahceci, Julia Frayer, Amr Ibrahim, and Sanela Pecenkovic, A Comparative Analysis of<br />
Actual Locational Marginal Prices in the PJM <strong>Market</strong> and Estimated Short-Run Marginal<br />
Costs: 2003-2006, London Economics International, Section 5.2, February 2007,<br />
http://www.publicpower.org/files/PDFs/LEIReport2012007.pdf<br />
77<br />
An example of the potential problems arising from the inclusion of opportunity costs can be<br />
seen in PJM’s Regulation <strong>Market</strong>. Participants in this market must submit cost-based offers,<br />
and if they fail the three pivotal supplier test, their offers are capped at the lower of the pricebased<br />
or cost-based offer, plus a margin and opportunity costs. Changes to the margin and<br />
the calculation of opportunity costs increased the cost of Regulation and led PJM’s <strong>Market</strong><br />
Monitor to conclude that the results of the Regulation <strong>Market</strong> were not competitive. 2010<br />
State of the <strong>Market</strong> Report for PJM, Section 6, Monitoring Analytics, March 20, 2011, p. 448-9,<br />
http://www.monitoringanalytics.com/reports/PJM_State_of_the_<strong>Market</strong>/2010/2010-sompjm-volume2-sec6.pdf<br />
30 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
Limited-run resources (e.g., generation units subject to air quality limitations<br />
on run times, and hydro units that must be operated for water use and<br />
recreational purposes as well as power supply production) would be allowed to<br />
include opportunity costs in the event that they are dispatched during a time<br />
when energy prices are lower than they would otherwise earn.<br />
Generators participating in RTO-run markets (whether the generators are<br />
inside the RTO footprint or importing into the RTO region) would be<br />
required to submit auditable SRMC information on the company’s entire<br />
portfolio of generation units to the MM. These data would be available to the<br />
public on RTO Web web sites, as would the offers submitted into the market.<br />
Any differences between supply offer curves submitted to the RTO<br />
optimization market and the cost data held by the MM would need to be<br />
justified by the generator upon request by the MM. 78<br />
A potential difficulty with implementation of the SRMC offer cap is that the<br />
generators will have an incentive to inflate their costs. APPA therefore<br />
recommends that FERC develop proxy costs based on available databases or<br />
individual supplier data, 79 as well as cost data submitted for units of similar ages<br />
and technologies. Owners of units whose costs exceeded proxy cost data would be<br />
asked to provide additional documentation to the MM explaining the differential.<br />
If this could not be supplied, their offers would be capped at the proxy cost.<br />
Even in the absence of a cost cap on offers into the optimization market, APPA<br />
strongly recommends that all data on offers to sell into wholesale energy markets<br />
be provided to the public on the next operating day, along with operating cost<br />
data submitted to the RTO, with the identities of the generating units unmasked.<br />
This would allow third parties to evaluate market performance and behavior in a<br />
way that only MMs currently can, enhancing transparency.<br />
To facilitate demand response participation in these markets, demand response<br />
offers would not be subject to the cost disclosure requirement; instead they would<br />
submit load-reduction demand curves or minimum price offers above which they<br />
would pledge to curtail a specified amount of load. Demand response offers<br />
clearing the market would receive the LMP less an appropriate offset to reflect<br />
the serving LSE’s cost of providing retail electric service to the reducing customer. 80<br />
78<br />
The existence of these differences would depend on the frequency with which generators submit<br />
cost data to RTOs. Very short-term swings in fuel prices, for example, might cause actual generator<br />
costs to deviate from the cost data held by the RTO. (One possible alternative would be to include<br />
some fluctuating fuel-specific index component in generator cost submissions.)<br />
79<br />
William H. Dunn, Jr., Data Required for <strong>Market</strong> Oversight, December 2007, p. 7 and footnote<br />
5, http://appanet.cms-plus.com/files/PDFs/dunn2007.pdf<br />
80<br />
This issue is discussed in great detail in the record of FERC Docket No. RM10-17-000. See, e.g.,<br />
Post-Technical Conference Comments of APPA, filed October 13, 2010, available at<br />
http://www.publicpower.org/files/PDFs/APPAPostTCDRcommentsRM1017101310asfiled.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 31
2) LSEs would be required to demonstrate to the RTO that they<br />
possess adequate amounts of generation capacity (either owned or<br />
contracted for) and demand-side resources to meet projected<br />
future needs. This RTO-established resource adequacy requirement for<br />
individual LSEs would prevent them from “leaning” on the optimization<br />
market and avoiding contracts for or investments in generation and demandside<br />
resources. It would also prevent the potential exercise of “buyer market<br />
power” (to the extent it might exist, a point which APPA does not concede),<br />
by imposing an obligation on buyers to enter into contract arrangements with<br />
sellers. Close coordination between regional and state-level policies and<br />
between RTOs and the state regulatory authorities in their footprints would<br />
be required to develop these resource requirements. The RTO would be<br />
responsible for determining the overall required level of reserves within its<br />
footprint, while state (or local) authorities would determine acceptable<br />
resource portfolios and other power supply attributes, e.g., contract terms,<br />
fuel mixes, and demand-side/generation ratios for their respective LSEs. The<br />
resource adequacy provisions of the APPA <strong>Plan</strong> are discussed further in<br />
Section X.<br />
3) A “must offer” requirement into the optimization market would<br />
apply to available resources, including resources not scheduled to<br />
serve loads under LSE ownership arrangements or bilateral<br />
agreements. This requirement would limit opportunities for strategic<br />
withholding behavior. Limited-run resources (e.g., generation units subject to<br />
air quality limitations on run times, and hydro units that must be operated for<br />
water use and recreational purposes as well as power supply production)<br />
would be exempted from the must offer requirement under most<br />
circumstances. Participation of variable resources, of course, would also be<br />
subject to their availability. Owners of generation would be required to submit<br />
a schedule of planned maintenance or refueling outages to the RTO and to<br />
demonstrate compliance with the must offer requirement periodically with<br />
the RTO. Providers of demand-side resources would be required to offer<br />
their resources and products into the optimization market to the extent<br />
required by any contractual or tariff provisions to which they had agreed.<br />
Another critical issue in designing a new RTO optimization market is the<br />
methodology used to establish prices. Current RTO markets use singleclearing-price<br />
auctions, where the market-clearing price is paid to all<br />
generators offering a price below the highest accepted offer, irrespective of<br />
their individual offers. To avoid too dramatic a departure from current<br />
market design and in an effort to achieve a compromise, APPA’s proposal<br />
would retain, at least initially, the single-clearing-price structure for use with<br />
the optimization market. Because of past issues with the single-clearing-price<br />
mechanism, however, APPA believes FERC should assess the operation of the<br />
32 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
evamped optimization market with this pricing mechanism no later than<br />
three years after the start of the market, with a focus on the restructured states<br />
where most generation is unregulated, to determine whether further market<br />
design changes are necessary to achieve just and reasonable rates, and<br />
therefore benefits to consumers.<br />
The ability to earn short-term profits above SRMC could, at the margin, drive<br />
some lower-cost resources into the RTO’s spot markets. 81 Simultaneously, the<br />
single-clearing-price auction would provide short-run and long-run price<br />
incentives for LSEs to develop longer-term portfolios of owned and<br />
contracted-for resources, to reduce reliance on the optimization market.<br />
However, the ability of bidders to engage in behavior intended to increase the<br />
single clearing price well above the marginal cost of even the clearing<br />
resource, (e.g., so-called “hockey stick bidding”), to the mutual benefit of all<br />
resource providers being paid the clearing price, would be greatly reduced by<br />
the SRMC-based offer requirement.<br />
Even more than short-term energy markets, ancillary services markets are<br />
particularly susceptible to the exercise of market power, in part because some<br />
services can be supplied only by a limited number of providers. 82 Given the<br />
cost-based offer and must-offer requirements in this proposal, the RTO can<br />
co-optimize supply offers across the energy and ancillary services markets.<br />
Under such a co-optimization, the RTO would simultaneously dispatch energy<br />
and ancillary services centrally, 83 paying generators meeting the technical<br />
criteria and selected to supply ancillary services on a cost-reimbursable basis, if<br />
they are not dispatched.<br />
81<br />
In theory, at the margin the uniform-price auction structure would also provide incentives for<br />
investment in low-cost generation resources. However, this is unlikely to be a significant factor<br />
in APPA’s proposed market redesign, in part because it is expected that this optimization market<br />
would be a small portion of overall electricity sales. Investment decisions would be driven<br />
primarily by the resource planning process.<br />
82<br />
See, e.g., 2010 State of the <strong>Market</strong> Report for PJM, Section 6 at 418 (“The Regulation <strong>Market</strong><br />
structure was evaluated as not competitive because the Regulation <strong>Market</strong> had one or more<br />
pivotal suppliers which failed PJM’s three pivotal supplier (TPS) test in73 percent of the<br />
hours.”) At 426, the report concluded that “Economic withholding remains a problem in the<br />
DASR [Day-Ahead Scheduling Reserve <strong>Market</strong>].”<br />
83<br />
As recommended by PJM’s MM, operating reserves should continue to be committed on an<br />
hour-ahead basis in combination with a five-minute joint energy market optimization, based<br />
on energy offers. For a more detailed discussion, see Protest and Compliance Proposal of the<br />
Independent <strong>Market</strong> Monitor for PJM, pp. 51-53.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 33
VIII. RTO Operations to Support Non-Discriminatory<br />
Transmission Access<br />
U<br />
nder APPA’s proposal, RTOs would emphasize activities that<br />
support wholesale power supply markets — ensuring<br />
nondiscriminatory transmission access and managing congestion<br />
on the transmission grid, thus ensuring reliability. RTOs would continue<br />
to provide transmission service under open access transmission tariffs<br />
(“OATTs”), dispatch generating units in merit (lowest cost) order<br />
subject to system constraints, manage integration of variable resources,<br />
determine price differentials arising from congestion, and assist LSEs in<br />
hedging congestion. In a market environment focused primarily on<br />
supporting long-term resource arrangements, including both bilateral<br />
contracting and LSE-owned resources, RTOs would need to improve<br />
their management of transmission congestion. As explained in greater<br />
detail in this chapter, they would need to:<br />
• Allocate financial transmission rights (“FTRs”) designed to support<br />
LSE power supply arrangements required to serve load.<br />
• Collect data on bilateral contracts entered into by market participants<br />
transacting within the RTO footprint.<br />
• Centrally dispatch generation in least-cost (merit) order based on<br />
actual costs of generation units submitted to the RTO.<br />
Financial Transmission Rights and Long-Term<br />
Transmission Rights<br />
RTOs would continue to offer OATT transmission service, but would<br />
implement policies to provide greater support to long-term power<br />
supply arrangements. RTOs would allocate annual FTRs or equivalent<br />
rights directly to LSEs based upon a percentage of the LSE’s peak load.<br />
Even where the bulk of energy is transacted through bilateral contracts,<br />
because all contracts would clear through the market, a hedge would<br />
still be needed against congestion costs. LSEs with mid-year changes to<br />
loads or resources should be permitted to apply to the RTO for a<br />
change in their FTR allocations. Any remaining congestion revenues<br />
would be distributed to network and long-term firm transmission<br />
customers to ensure that market participants paying the embedded cost<br />
of the transmission system would receive the full economic value of<br />
their payments or equivalent rights. Non-load-serving market<br />
participants would not be eligible to receive an allocation of FTRs, but<br />
LSEs would retain the right to resell their allocated FTRs if they chose.<br />
RTOs would also allocate LTTRs to LSEs to support bilateral contracts<br />
or owned resources, with a priority for power supply arrangements of 10<br />
years or longer. 84 These LTTRs would be paired with LSEs’ power<br />
supply arrangements developed to comply with the RTO’s resource<br />
adequacy requirements, and applicable state resource procurement<br />
requirements. One means to distribute LTTRs would be to provide the<br />
34 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
LTTR along with approval of new network transmission service for the<br />
LSE.<br />
However, without adequate transmission infrastructure in place during<br />
the term of the LTTR to support transmission service, the LTTRs might<br />
not provide a sufficient hedge to LSEs against congestion costs. Under<br />
the regulations promulgated in Order No. 2000, an RTO must possess<br />
the authority “for directing or arranging necessary transmission<br />
expansions, additions and upgrades that will enable it to provide<br />
efficient, reliable and non-discriminatory service.” 85 FERC decisions<br />
since that order, however, have cast some doubt on this requirement,<br />
and hence on the potential revenue adequacy of LTTRs over their full<br />
term. 86 Such financial uncertainties in turn make it more difficult and<br />
costly to develop new generation resources. RTOs should be required to<br />
demonstrate that the data on projected loads and planned resources is<br />
incorporated into transmission system planning and expansion plans, to<br />
ensure that the RTO’s transmission system is sufficiently robust to<br />
support LSE resource portfolios.<br />
The Commission’s currently pending Notice of Proposed Rulemaking in<br />
Docket No. RM10-23-000 87 proposes to revise regional transmission<br />
planning and cost allocation protocols and procedures. APPA believes<br />
that if properly done, regional transmission planning could support<br />
allocations of LTTRs to support LSE resource plans. Such resource<br />
plans would inevitably reflect applicable state resource procurement<br />
policies (such as renewable portfolio standards). Therefore,<br />
transmission facilities that are in fact needed to support LSE-selected<br />
generation resources will be necessarily included in RTO’s regional<br />
transmission plans, presuming those plans are based upon the resource<br />
plans of LSEs in the region. Reductions in reliance on transmission<br />
facilities due to increased use of energy efficiency and distributed<br />
generation would likewise be taken into account.<br />
APPA, however, is quite concerned that FERC’s Order No. 741, its final<br />
rule on RTO credit requirements issued on October 21, 2010, in Docket<br />
85<br />
18 C.F.R. § 35.34(k)(7).<br />
86<br />
Midwest Independent Transmission System Operator Inc., 125 FERC 61,061, P 34 (2008)<br />
(“While we recognize that the Midwest ISO has the obligation to facilitate generation interconnections<br />
and expansion planning, it cannot force utilities to build capacity. The Midwest<br />
ISO therefore cannot be required to build sufficient transmission capacity to ensure deliverability<br />
of all resources for their useful life.”); Midwest Independent Transmission System Operator<br />
Inc., 125 FERC 61,062, P 162 (2008) (“Also, while the Midwest ISO is obligated to<br />
facilitate generation interconnection and expansion planning, it cannot force utilities to<br />
build capacity and therefore it cannot assure deliverability for all projects’ useful lives.”).<br />
87<br />
Transmission <strong>Plan</strong>ning and Cost Allocation by Transmission Owning and Operating <strong>Public</strong><br />
Utilities, 75 Fed. Reg. 37,884 (June 30, 2010).<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 35
No. RM10-13-000, 88 will greatly discourage LSEs from attempting to<br />
obtain LTTRs to support new generation resources, including renewable<br />
resources. The Commission in that order decided to require LSEs<br />
holding FTRs, including LTTRs, to post full financial security to support<br />
all such holdings, despite the acknowledged difficulty in valuing such<br />
holdings for security purposes. Providing such security could well make<br />
it so financially onerous to hold LTTRs that LSEs will be faced with the<br />
decision either to (1) simply accept the risk of transmission congestion<br />
costs associated with such long-term resource transactions; or (2) not<br />
enter into such longer-term transactions in the first instance. Neither<br />
result will assist in assuring the development of the new generation<br />
resources that will undoubtedly be needed in the coming years as<br />
increasing numbers of coal-fired power plants leave RTO generation<br />
fleets.<br />
Collection of Bilateral Contract Data<br />
LSEs would submit their proposed bilateral contracts and owned generation<br />
resource arrangements to the RTO. The RTO would then subject these<br />
contracts and arrangements to a simultaneous feasibility test to determine<br />
whether they violate any transmission system constraints or overload any<br />
system equipment. This information, however, would not affect the dispatch,<br />
which would be done according to actual generator costs and transmission<br />
constraints and would be performed separate from the terms of the<br />
contracts. Bilateral contracts would act as financial arrangements<br />
determining the payment streams between buyers and sellers. The feasibility<br />
test would, however, feed into determinations of FTRs/LTTRs and plans for<br />
transmission expansions and upgrades.<br />
Guidelines for allocating FTRs and LTTRs would need to be established in<br />
the event that all of the power supply arrangements submitted to the RTO<br />
during a particular time window cannot pass the feasibility test. For<br />
example, priority could be given to LSE power supply arrangements with<br />
longer terms, or arrangements that LSEs enter into to meet their service<br />
obligations, as discussed above. The RTO should include such contracts and<br />
arrangements in its regional transmission plan, and ensure that sufficient<br />
transmission facilities are constructed as needed to support them.<br />
Centralized Dispatch<br />
The RTO would centrally dispatch all generation within its footprint,<br />
regardless of whether it is an owned resource, scheduled under a bilateral<br />
contract, or offered to the optimization market. The RTO would use a cost-<br />
88<br />
75 Fed. Reg. 65,942 (October 27, 2010).<br />
36 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
ased security-constrained economic dispatch formulation (similar to how<br />
current RTOs operate, except that the RTO would be using actual cost data<br />
of the bidders, rather than submitted bids). 89 The terms of the bilateral<br />
contracts would reflect the financial arrangements to be settled between the<br />
buyers and sellers, and would be settled separately from the actual dispatch.<br />
Generators would be paid based on prices negotiated through the bilateral<br />
contracts, or set in the optimization market, as applicable.<br />
89<br />
Generators would be permitted to designate a zero cost for dispatch purposes if they needed<br />
to dispatch owned resources, to meet contractual obligations or to keep a unit running for<br />
operational reasons.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 37
IX. Renewable Energy<br />
A<br />
t least 30 states 90 states have implemented renewable portfolio<br />
standards (RPS) or goals under which LSEs are required to provide a<br />
portion of their sales or capacity requirements from renewable or lowemissions<br />
generation sources, or from energy efficiency measures. Moreover,<br />
proposals have been made in Congress to enact a national renewable<br />
electricity standard (RES) or clean energy standard (CES). From the point of<br />
view of the RTO, such requirements effectively amount to giving alternative<br />
renewable energy sources some level of priority in the dispatch mix. Some<br />
alternative energy sources, such as biomass or geothermal, can simply<br />
participate in the bilateral market along with traditional fossil and nuclear<br />
generators. Variable renewable generation sources such as wind and solar,<br />
however, can be more difficult to integrate into RTO dispatch mixes, since<br />
there may be a higher risk of unavailability during a particular time interval.<br />
APPA designed its proposed market reform plan to be compatible with such<br />
renewable energy goals and the complications associated with scheduling<br />
variable energy sources. Rather than being set by the “market,” the<br />
penetration level of these variable renewable generation sources will likely be<br />
set based on RPS requirements and other policy considerations determined<br />
by federal, state and local regulators, governors and legislatures.<br />
Operationally, the RTO would simply have to schedule these resources when<br />
they are available (either directly or through individual LSE schedules),<br />
possibly backing down other sources of generation in the process (this<br />
becomes an issue when variable generation resources reach a significant<br />
penetration level within an operating area). In the Day Two markets, which<br />
require a day-ahead commitment of generating units, short-term changes in<br />
output of such variable resources may require the purchase of conventional<br />
power in real-time if the variable resource cannot deliver the day-ahead<br />
commitment in real time, or a reduction in other committed resources if<br />
there is a greater amount delivered.<br />
Since variable resources often are not available at the full contracted amount<br />
in a particular hour, they must be “firmed up” in some manner. One way to<br />
do this would be to require LSEs scheduling wind or solar resources to<br />
develop portfolios of resources that include appropriate backup capacity (e.g.,<br />
natural gas or hydroelectric power). 91 But cost of the capacity should be<br />
borne by the variable resource provider as an incentive to schedule as<br />
accurately as they can, as discussed below. These portfolios could be<br />
90<br />
Renewable Portfolio Standards and State Mandates by State, U.S. Energy Information Administration,<br />
August 2010, based on 2008 data, http://www.eia.doe.gov/cneaf/solar.renewables/page/trends/table28.html<br />
91<br />
This type of arrangement has been explored by C.L. Anderson and J. Cardell , Reducing the<br />
Variability of Wind <strong>Power</strong> Generation for Participation in Day-Ahead <strong>Market</strong>s, Proc. of the<br />
41st Hawaii International Conference on System Sciences, Waikoloa, Hawaii, 2008.<br />
38 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
determined by the states in the power supply planning processes described in<br />
Chapters IV and X. Alternatively LSEs would be required to purchase<br />
adequate operating reserves through the ancillary services market to support<br />
their variable resources, with the cost reimbursed by the variable resource<br />
provider. Since this could involve large amounts of operating reserves, the<br />
RTO and state-level regulators would need to cooperatively determine<br />
regional solutions for handling variable resources as part of the resource<br />
adequacy and transmission planning processes. 92<br />
One step that could be taken to reduce the amount of capacity or operating reserves<br />
needed is not related to RTO- markets, and simply involves improvements in the<br />
science of forecasting. Obtaining more accurate data and incorporating that data into<br />
scheduling regimes, would be more fruitful than developing entire new market<br />
design features to accommodate variable resources.<br />
In recognition of the difficulty of precisely scheduling variable resources,<br />
APPA has supported the elimination of third-tier imbalance penalties. But<br />
variable resource owners and operators also should have the financial<br />
incentive to schedule as accurately as possible. A combination of carrots and<br />
sticks (e.g., increased opportunities for variable resources to schedule within<br />
the scheduling day and hour, payment by such resources of the associated<br />
capacity and operating reserves, increased access to better forecasting data,<br />
and more coordination by transmission service providers across balancing<br />
areas) should serve to both assist and discipline variable resource providers.<br />
FERC proposed certain measures to promote the integration of variable<br />
resources in a proposed rule issued in November, 2010 93 that would require<br />
transmission providers to offer all customers the option to schedule<br />
transmission service at 15-minute intervals instead of the current hourly<br />
scheduling norm, and to offer regulation service to generators located within<br />
a transmission provider’s balancing authority area. 94 The proposed rule also<br />
would amend the standard interconnection agreement for large generators to<br />
require variable generators to provide meteorological and operational data to<br />
92<br />
In its comments filed on the Commission’s Notice of Inquiry in Integration of Variable Energy<br />
Resources, FERC Docket No. RM10-11-000, on April 12, 2010, APPA commented at length on<br />
possible measures FERC could require transmission providers to take to better integrate variable<br />
energy resources into regional transmission systems. APPA’s comments are available at<br />
http://www.publicpower.org/files/PDFs/APPARM1011Comments41210asfiled.pdf<br />
93<br />
Integration of Variable Energy Resources, Notice of Proposed Rulemaking, 133 FERC <br />
61,149, (November 18, 2010), 75 Fed Reg. 75,336 (December 2, 2010)<br />
94<br />
The proposed rule would add a new rate schedule for this mandatory service, including a<br />
mechanism through which transmission providers can recover the costs. A transmission<br />
provider could not require a variable generator to purchase greater volumes of generator regulation<br />
service than conventional generators unless the transmission provider offers 15-<br />
minute scheduling and power production forecasting, and can demonstrate that any<br />
requirement that variable generators purchase more regulation service is commensurate with<br />
their proportionate effect on net system variability.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 39
The increased reliance on longer<br />
termlonger-term PPAs in the APPA<br />
plan may therefore better support<br />
new renewable resource<br />
development than the current shortterm<br />
RTO market model.<br />
transmission providers, and "encourage" transmission providers to develop<br />
power production forecasting for variable generators.<br />
As additional amounts of variable resources are integrated into the grid, there<br />
will be a greater need for capacity and operating reserves as backup power.<br />
This additional resource need reinforces the importance of market reforms to<br />
avoid expenditure of additional and unnecessary costs. For example, recent<br />
increases in locational capacity prices in PJM would make wind power<br />
integration more expensive as additional capacity to back up the wind power<br />
has to be purchased at these higher prices. In the event that scarcity pricing is<br />
implemented, tapping into operating reserves could trigger the increases in<br />
the price ceiling and similarly create additional costs for consumers.<br />
Reforming capacity markets and limiting the use of scarcity pricing would<br />
therefore make integration of renewable resources more affordable.<br />
APPA also notes that distributed (local) generation, energy storage and micro-grids<br />
are emerging alternative energy sources that may not be included in current RPS<br />
regimes but may benefit consumers more when compared to the price of purchasing<br />
energy from the grid. During times of peak or rapidly fluctuating demand, local<br />
generation or energy storage may also impart significant benefits to the grid as a<br />
whole, relieving strain on transmission and generation facilities. The RTO would need<br />
to develop tariff provisions accommodating LSE use of these distributed generation<br />
sources as a way to meet resource adequacy requirements.<br />
An assertion that has been made repeatedly in the ongoing debate over restructured<br />
markets is that RTO-operated markets are more advantageous for renewable power. 95<br />
As stated earlier, because this <strong>Plan</strong> leaves intact the beneficial functions of RTOs, such<br />
as the ability to dispatch a wide array of resources and elimination of pancaked<br />
transmission rates, these advantages of RTOs for renewable power would not change.<br />
Finally, RTO operations are secondary to the importance of providing longterm<br />
revenue stability for investors in renewable energy through long-term<br />
contracts. The importance of long-term contracts for renewable power is<br />
demonstrated by a Department of Energy (DOE) finding that in 2009, 58<br />
percent of new wind capacity was purchased by investor-owned or public<br />
power utilities under long-term contracts. 96 Regarding the 38% of wind sold<br />
as merchant power into the wholesale markets, the DOE concludes “that it is<br />
95<br />
For example, see Joint Statement Supporting <strong>Competitive</strong> Wholesale Electricity <strong>Market</strong>s,<br />
<strong>American</strong> Wind Energy <strong>Association</strong> and the COMPETE Coalition, October 2010,<br />
http://www.competecoalition.com/resources/compete-awea-joint-statement-supporting-competitive-wholesale-electricity-markets<br />
96<br />
2009 Wind Technologies market Report, Office of Energy Efficiency and Renewable Energy,<br />
US Department of Energy, August 2010,<br />
http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf,<br />
40 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
possible that many projects that sold power on a merchant basis in 2009 may<br />
now be seeking longer-term PPAs in order to gain increased revenue stability.”<br />
In fact, it has become increasingly apparent, that, without a long-term<br />
contract, financing renewables is nearly impossible in many cases. An article<br />
on renewable energy projects in The International Business Times states:<br />
“Now, projects without strong institutional backing and a signed, long-term<br />
PPA won't even make it to bank credit committees.” The increased reliance<br />
on longer-term PPAs in the APPA plan may therefore better support new<br />
renewable resource development than the current short-term RTO market<br />
model.<br />
97<br />
The Week in Green Energy: The Bankable Project, International Business Times, November<br />
21, 2010; http://uk.ibtimes.com/articles/20101121/week-green-energy-bankable-project.htm<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 41
X. Resource Adequacy and <strong>Plan</strong>ning<br />
A<br />
PPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> does not include any explicit RTOadministered<br />
payments or markets for generation capacity. Studies of<br />
the PJM and NY ISO capacity markets reveal that these markets have<br />
generated payments to generators far in excess of what would be needed to<br />
cover the actual costs of new capacity needed for reliability. 98 A recent analysis<br />
shows that high prices within the constrained zones in PJM’s Reliability<br />
Pricing Model have not incented greater levels of new generation clearing the<br />
RPM auctions or higher offers of existing plant upgrades, demand response,<br />
energy efficiency resources, and net imports in constrained zones. 99<br />
Given these flaws in the RTO-operated capacity markets, APPA believes it<br />
would be far better to use a combination of resource adequacy requirements,<br />
a comprehensive transmission planning process, and long-term bilateral<br />
power supply and demand response arrangements to ensure adequate supply<br />
resources in RTO regions in future years. If desired by the stakeholders in a<br />
particular RTO region, a voluntary residual capacity market could also be<br />
included in the array of options for those LSEs finding themselves short of<br />
capacity in the nearer term.<br />
Overall RTO-established resource adequacy standards applicable to all LSEs<br />
are an important feature of the APPA proposal. 100 These standards may have<br />
to be tailored by the RTO for specific subregions within its footprint,<br />
depending on transmission constraints and other factors. APPA is aware that<br />
there are jurisdictional disputes over the exact level and nature of RTO-set<br />
resource adequacy requirements. Generation adequacy requirements<br />
traditionally have been the purview of state utility regulators and reliability<br />
entities. An increased RTO/federal role would require coordination and<br />
cooperation among state regulators, RTOs, and FERC in establishing and<br />
approving regional resource adequacy plans. This section lays out in more<br />
detail the resource adequacy provisions of the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>.<br />
Appendix A of this paper provides a background discussion on the current<br />
resource adequacy provisions in restructured markets.<br />
APPA’s proposal would establish a multi-state regional process to develop<br />
needed RTO-wide resource adequacy requirements under agreed-upon policy<br />
goals. States would then implement procurement processes to ensure that<br />
state-regulated IOU LSEs obtain a diversified portfolio of power supply and<br />
demand-side resources of varying lengths and terms that will assist in meeting<br />
98<br />
See Mount (2007) and Wilson (2008).<br />
99<br />
Direct Testimony of James F. Wilson in Support of First Brief of the Joint Filing Supporters,<br />
Federal Energy Regulatory Commission, Docket ER10-787, July 1, 2010, Section V,<br />
http://www.wilsonenec.com/FCM_Testimony_July_1.php<br />
100<br />
These standards would be applied to a number of years going forward, with the precise time<br />
frame to be determined.<br />
42 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
the RTO-wide resource adequacy requirements. 101 States and LSEs could also<br />
agree to pool their LSEs’ respective resource needs for procurement<br />
purposes, rather than having each individual state or LSE act on its own. Such<br />
procurement processes would greatly benefit new suppliers of generation,<br />
demand response and energy efficiency technologies by providing revenue<br />
streams needed to support long-term financing. Sufficient safeguards also<br />
need to be included in the selection process to ensure that third-party<br />
suppliers get fair and equitable consideration of their offers and proposed<br />
projects. 102<br />
Demand response resources should be fully considered in developing LSE<br />
resource portfolios. But caution should be exercised to avoid overreliance on<br />
demand response resources, which have accounted for an increasingly<br />
substantial percentage of the reliability requirements in recent years. 103 In the<br />
2010 auction in ISO-NE’s Forward Capacity <strong>Market</strong>, 8.7 percent of the<br />
capacity procured was demand response. 104 In PJM, demand response was<br />
6.3% of peak load in the 2010/2011 delivery year, approaching PJM’s prior<br />
7.5% limit for the limited demand response product. 105<br />
101<br />
<strong>Public</strong> power and cooperative utilities in RTO regions, because they have retained their obligation<br />
to serve retail customers, already develop and implement such resource adequacy<br />
plans, under the supervision of their local governing bodies. They conduct periodic generation<br />
procurements, assessing “buy v. build” generation options, as well as the use of demand<br />
response and energy efficiency measures to reduce demand, in lieu of securing additional<br />
generation. Because they are not-for-profit and do not earn a return on owned generation assets<br />
as investor-owned utilities do, they approach these decisions from a consumer-benefit perspective.<br />
For these reasons, public power utilities should continue to procure their resources<br />
under their own plans, unless they choose to opt into a larger state procurement process.<br />
102<br />
State competitive procurement “best practices” are discussed at length in a 2008 paper prepared<br />
for the Collaborative on <strong>Competitive</strong> Procurements between FERC and the National<br />
<strong>Association</strong> of Regulatory Utility Commissioners (NARUC). Susan Tierney and Todd<br />
Schatzki, <strong>Competitive</strong> Procurement of Retail Electricity Supply: Recent Trends in State Policies<br />
and Utility Practices, July 2008, http://www.naruc.org/<strong>Public</strong>ations/NARUC%20<strong>Competitive</strong>%20Procurement%20Final.pdf<br />
103<br />
The North <strong>American</strong> Electric Reliability Corporation (NERC) listed the “Uncertainty of Sustained<br />
Participation in Demand Response Programs” as one of the Emerging Reliability Issues<br />
in 2010, stating that: “While many similarities exist between Demand Response and generating<br />
capacity, key differences in terms of availability, performance, and sustainability may appear<br />
as a given system becomes more stressed… Demand Response is increasingly being used<br />
to balance system load and relieve resource adequacy and transmission reliability issues. Decreased<br />
or insufficient participation could lead to operational challenges where peak demand<br />
is not able to be met by current generation or transmission resources.” 2010 Long Term Reliability<br />
Assessment, p. 59.<br />
104<br />
Final Capacity Auction Results: Surplus Resources Available for 2013–2014, ISO-New England,<br />
http://www.iso-ne.com/nwsiss/pr/2010/fca4_filing_release.pdf. The table on p. 3<br />
shows that 37,501 MW of capacity was acquired, of which 3, 261 MW was demand resources.<br />
105<br />
Demand Resource Saturation Analysis, Resource Adequacy <strong>Plan</strong>ning Department, PJM, May 2010,<br />
http://www.pjm.com/~/media/committees-groups/committees/oc/20100817/20100817-item-<br />
03-demand-response-saturation-report.ashx. PJM has recommended increasing the limit to 8.5%<br />
for the RTO, finding that this level would produce a low probability (10%) of a resource being interrupted<br />
more than 10 times<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 43
Given these high levels, the risks of future potential non-performance of<br />
demand response resources need to be assessed. Were large amounts of<br />
demand response not to materialize when called upon, the result would be an<br />
adverse impact on system operations comparable to the sudden loss of a large<br />
amount of variable generation. APPA accordingly supports the right of the<br />
RTO to impose technical requirements and verification criteria on demand<br />
response resources to ensure that these resources do perform as intended, if<br />
they are to be counted in an LSE’s resource portfolio. Such requirements and<br />
criteria, however, must be well supported to avoid discriminating against<br />
demand response and in favor of other resources.<br />
Energy efficiency investments as an alternative to generation resource<br />
obligations must also be fully considered. Given that utility LSEs already<br />
provide retail service to end-use customers, the LSE may be the lowest-cost<br />
supplier of demand response or efficiency services. But as part of the regional<br />
procurement process, third-party demand response providers could bid to<br />
provide such services to LSEs. Because demand-side resources may in fact be<br />
the lowest-price supply options (in addition to being the lowest carbonemitting<br />
options), they should be an important part of the resource portfolio<br />
for the region and for LSEs.<br />
State requirements and policy preferences for fuel diversity (such as state RPS<br />
and energy efficiency goals, and state/regional carbon mitigation regimes)<br />
should be honored in developing LSE resource portfolios. The RTO would<br />
have to ensure, however, that the LSE resource portfolios developed are,<br />
taken as a whole, both technically feasible and operationally reliable. 106 (For<br />
example, an LSE’s 50 percent wind portfolio might exceed an applicable state<br />
RPS requirement, but it would not necessarily be adequate or reliable from<br />
the RTO’s standpoint unless sufficient backup supply/storage were available.)<br />
Another important issue in constructing competitive procurements for stateregulated<br />
LSEs is to determine who will conduct the solicitation for bids and<br />
evaluate the submitted bids. The details of current programs vary from state<br />
to state, but in general, current state auctions or bidding programs to<br />
determine which suppliers will supply retail customers are either conducted<br />
by the state commission directly (for example, Maine or New Jersey) or by the<br />
regulated utility (that is, the LSE) under the supervision and oversight of its<br />
state commission (for example, Delaware, Maryland, or Massachusetts). 107 An<br />
106<br />
One issue that may arise is whether to allow “liquidated damages” contracts to be included in<br />
an LSE’s resource portfolio, and to count towards meeting the RTO’s resource adequacy requirement.<br />
Although not directly linked to a specific generating unit, such contracts should<br />
be allowed at least for a transitional period, so that LSEs may continue to use existing agreements<br />
in their portfolios to meet the relevant standards in the short run, and transition to<br />
qualifying power supply arrangements.<br />
107<br />
If the regulated utility is to take the lead, this should be done under the close supervision of<br />
the relevant state commission.<br />
44 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
independent third party designated by the state or LSE (with state approval)<br />
could also administer the procurement process.<br />
Once the selection of the resources is determined, contractual arrangements<br />
with the suppliers or providers of the resources (including arrangements for<br />
selected self-build options) would be made. The objective would be for LSEs<br />
to have a diversified portfolio of resources, including longer-term supply<br />
commitments that provide customers electricity at a relatively stable and<br />
reasonable price, while assuring suppliers a steady revenue stream that can<br />
support financing of new resources. APPA’s intention here is to recapture the<br />
benefits to consumers of the long-term commitments and obligations that<br />
regulated utilities had under traditional cost-based regulation to provide<br />
reliable electricity at a just and reasonable price, while at the same time taking<br />
full advantage of available wholesale competitive options to discipline prices<br />
and suppliers. As previously discussed, these longer-term contracts would be<br />
balanced by a portfolio of medium- and short- term contracts.<br />
APPA’s plan has the following advantages over the current system:<br />
• The planning and procurement process can provide a means for meeting<br />
individual state policy goals in a regional process (such as renewable<br />
portfolio standards or demand management programs).<br />
• Progress can be monitored as the process moves through the planning<br />
and procurement stages and any necessary adjustments can be made<br />
along the way. Accountability for LSE resource adequacy is left primarily<br />
to the states and LSEs.<br />
• This method allows the resource planning and procurement process to<br />
be conducted by the parties involved (LSEs and states), after the RTOwide<br />
determination is made on overall resource adequacy requirements.<br />
• The use of competitive procurement processes, including self-build<br />
options, to make the actual resource selections allows for competitive<br />
forces to provide price discipline on wholesale resource decisions.<br />
• Increased reliance on longer-term supply commitments should reduce<br />
the supply adequacy problems caused by overreliance on short-term<br />
RTO-run energy markets and the overpayments for existing capacity<br />
produced by some RTO-run locational capacity markets.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 45
46 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
XI. Transmission <strong>Plan</strong>ning<br />
A<br />
parallel effort to create a more integrated transmission planning,<br />
siting and construction process would also be necessary to implement<br />
APPA’s proposed market reforms. A critical and yet to be resolved issue<br />
is transmission congestion that remains in key pockets of regional<br />
transmission systems. Relying on the transmission owner members of RTOs<br />
themselves to build transmission facilities in response to congestion-based<br />
“pricing signals” in Day Two RTOs generally has not worked well. The<br />
Commission’s pending notice of proposed rulemaking on transmission<br />
planning and cost allocation is clearly intended to improve transmission<br />
planning processes. APPA believes that RTO transmission planning and cost<br />
allocation processes could be greatly improved by more specifically<br />
incorporating LSE resource plans, and that such incorporation is in fact<br />
required under Section 217(b)(4) of the Federal <strong>Power</strong> Act. 108<br />
Current RTO transmission planning processes lack a clear linkage between<br />
LSEs’ long-term resource commitments and long-term transmission<br />
availability (in the form of viable LTTRs that would fully hedge associated<br />
transmission congestion costs). As discussed earlier, not only does the<br />
<strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> recommend that LSEs with long-term power supply<br />
arrangements be given priority in allocating LTTRs/FTRs, but also that LSEs’<br />
long-term resource portfolio choices feed directly into RTO transmission<br />
planning. Priority should be given to transmission infrastructure needed to<br />
support such resource arrangements.<br />
RTO transmission planning processes require cooperation among the RTO’s<br />
transmission owners to construct the transmission facilities needed to serve<br />
the present and future needs of the entire region. Incentives to do so,<br />
however, are muddied by thorny cost allocation issues, the prospect of tough<br />
siting battles and generation/transmission cross-ownership.<br />
A related problem is that of transmission constraints that affect resource<br />
decisions. For example, if an LSE wishes to contract for long-term power<br />
supplies from a generation unit at a specific location in the RTO’s footprint,<br />
but there are transmission constraints between the proposed resource and the<br />
LSE’s load, how should this be handled Ultimately, the RTO would need<br />
legal support from state authorities and FERC to require member<br />
transmission owners to construct sufficient transmission upgrades to support<br />
LSEs’ long-term power supply choices, as incorporated into their resource<br />
portfolios.<br />
Even when transmission owners in RTO regions have undertaken substantial<br />
108<br />
For a fuller discussion of APPA’s views on the Commission’s pending NOPR on transmission<br />
planning and cost allocation, see the initial comments APPA filed on September 29, 2010, in<br />
Docket RM10-23-000, available at<br />
http://www.publicpower.org/files/PDFs/APPARM1023Comments92910asfiled.pdf<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 47
new transmission projects, they have insisted on (and generally obtained from<br />
FERC) very generous transmission rate incentives that unduly increase retail<br />
electric rates to consumers. The granting of transmission rate incentives,<br />
rather than being reserved for those cases in which incentives are truly<br />
needed to move a transmission project forward, are now often being granted<br />
by the Commission routinely. Moreover, the packages of incentives granted,<br />
taken together, can go far beyond what is required to reduce the risk of a<br />
transmission project to reasonable levels. While it is indisputable that<br />
additional transmission infrastructure is needed, the Commission’s failure to<br />
keep the costs of that additional infrastructure within reasonable bounds is<br />
contributing to growing opposition to the allocation of the resulting costs of<br />
such projects.<br />
APPA therefore supports the Commission’s issuance of its May 2011 Notice of<br />
Inquiry 109 seeking comments on its transmission rate incentive policy first set<br />
out in Order No. 679. 110 APPA believes that transmission rate incentives<br />
should be granted only to extraordinary transmission projects that are found<br />
to be needed and that would not be constructed but for the granting of such<br />
incentives. Moreover, the incentives should be limited to a reasonable<br />
package of measures that, taken together, reduce the risk of the project to<br />
acceptable levels for both project applicants and end- use consumers, without<br />
resulting in unjust and unreasonable rates. 111<br />
109<br />
Promoting Transmission Investment through Pricing Reform, Notice of Inquiry, 135 FERC 61,<br />
146 (May 19, 2011)<br />
110<br />
Promoting Transmission Investment Through Pricing Reform, Order No. 679, FERC Stats. &<br />
Regs. 31,222 (2006), order on reh’g, Order No. 679-A, FERC Stats. & Regs. 31,236, and<br />
order on reh’g, 119 FERC 61,062 (2007). APPA welcomes recent indications from the Commission<br />
that it recognizes the need for such a review. For example, FERC Commissioner John<br />
Norris voiced concerns similar to those of APPA in his 2010 concurrence to an order approving<br />
certain incentives for a transmission project in the PJM region:<br />
“…[T]he Commission’s current approach may not appropriately balance the different types of<br />
incentives awarded to a project. Some incentives, such as the collection of rates during construction<br />
work in progress (CWIP) and the approved recovery of prudently incurred costs if<br />
the project is abandoned, serve to substantially lower risk for investors in the project. Other<br />
kinds of incentives, such as an incentive ROE adder, give investors the opportunity for greater<br />
rewards. The Commission has not articulated a sufficiently clear framework to balance requests<br />
for packages of incentives that individually seek to both limit downside risk and provide<br />
greater potential upside rewards.” [Emphasis supplied.]<br />
Potomac Appalachian Transmission Highline, L.L.C., 133 FERC 61,152 at 61,737 (2010)<br />
(PATH)<br />
111<br />
For a more detailed discussion of the transmission rate incentives issue, see the Joint Comments of the<br />
<strong>American</strong> Chemistry Council, et al., Docket RM10-23-000, Federal Energy Regulatory Commission, September<br />
29, 2010, http://www.publicpower.org/files/PDFs/JointCommentsRM102320100929.pdf<br />
48 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
XII.<br />
Transition Issues<br />
I<br />
t has now been over a decade since the Federal Energy Regulatory<br />
Commission issued Order No. 2000. The course of RTO market<br />
development since that time has been difficult and controversial. The<br />
transition period to implement needed RTO market reforms is also likely to<br />
be prolonged and contentious, with bumps in the road and the possible need<br />
for mid-course corrections.<br />
For market participants that have made investments and resource<br />
procurement decisions under existing market structures that would be<br />
undergoing changes, implementation of the APPA <strong>Plan</strong> would likely require<br />
mechanisms to avoid or at least minimize economic injury during a<br />
substantial transition phase. For example, owners of capacity and demand<br />
response providers receiving payments under an RTO-run locational capacity<br />
market may require an orderly phasing out of such payments over the<br />
remaining term of the RTO’s forward market auction windows, even as<br />
resource adequacy requirements for LSEs are phased in.<br />
APPA’s proposed market redesign, which couples bilateral contracts and<br />
resource ownership with centralized dispatch, is compatible with FTRs, as are<br />
current RTO markets. Because this plan would not reinstitute physical<br />
transmission rights, the transition would be less difficult. The transition might,<br />
however, still impact the FTR holdings of some market participants. Since<br />
real-time dispatch would be based on costs rather than on market-based<br />
offers, the pattern of power flows in the transmission network would change<br />
to the extent that past market-based supply offers have been different than<br />
costs.<br />
Many aspects of the APPA <strong>Plan</strong>, such as the requirement for submission of<br />
short-run marginal costs for dispatch and optimization markets, may require<br />
FERC proceedings to work out the details, and likely would prove<br />
contentious. The recommendations for state-supervised procurement<br />
processes for state-regulated LSEs will likely entail state-level regulatory<br />
changes, or even new legislation. But even before the completion of the<br />
transition, steps taken to implement the <strong>Plan</strong>’s features could have near-term<br />
positive impacts on financing availability, by increasing the confidence in<br />
electricity markets on the part of lenders and investors. Moreover, reform of<br />
the RTOs’ short-term markets alone might have a salutary effect on the<br />
bilateral markets, providing an incentive for generators to offer more<br />
customized and attractive products and to bargain in a more meaningful<br />
fashion with prospective buyers.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 49
XII.<br />
Conclusion<br />
I<br />
mplementation of the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong> would take a<br />
substantial period of time. Many thorny transition issues would have to<br />
be resolved. There are substantial institutional and political obstacles as<br />
well. Differences in market design details among RTOs and differences in<br />
state retail regulatory regimes would require customized application of APPA’s<br />
<strong>Plan</strong> in each RTO. Hence, APPA suggests its <strong>Plan</strong> as one path to reach<br />
necessary long-term goals for the electric utility industry, including the<br />
development of new financial arrangements necessary to support new<br />
resource development in the wake of the 2008 financial crisis and subsequent<br />
deep recession, and in anticipation of a coming wave of coal generation unit<br />
retirements triggered by EPA regulatory actions<br />
Above all, APPA intended by proposing its <strong>Plan</strong> in 2009 to start a rational<br />
debate about the future of RTO markets—a debate the industry now more<br />
than ever needs more than ever to have. RTO-run centralized power supply<br />
markets are not working as originally envisioned. The resulting dysfunction<br />
has had substantial negative implications for the economy, reliability and the<br />
cost of retail electric service in RTO regions. The industry needs to start<br />
talking about necessary reforms. Before this dialogue can commence,<br />
however, those who advocate “competition” in wholesale electric markets have<br />
to acknowledge the current substantial problems with RTO-run centralized<br />
power markets. The debate should no longer be about whowhom can best<br />
massage the statistics or whether it is more virtuous to support “competition”<br />
or “regulation.” Instead, the industry must work together to develop a<br />
regulatory regime for electricity markets in RTO regions that will truly benefit<br />
consumers, businesses and the environment. Unless the electric utility<br />
industry and all of its regulators, retail and wholesale, can agree on a market<br />
design and regulatory paradigm that fairly balances the interests of both load<br />
and generation, the industry will be condemned to continued upheaval.<br />
50 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
APPENDIX A<br />
Division of Responsibilities for Resource Adequacy<br />
in Current RTO <strong>Market</strong> Structures<br />
The current RTO market structure has not provided for a robust set of<br />
resources to meet future projected demand at reasonable costs, nor has it<br />
produced sufficient diversity of fuel supply or low-carbon energy<br />
development. In short, sole reliance on “market” forces to determine resource<br />
amounts and fuel mixes is not likely to achieve such goals. Long-term<br />
planning and better-supervised resource procurement is therefore needed for<br />
resource adequacy of supply and demand resources and transmission.<br />
Achievement of such goals is critical to the RTO’s ability to support longerterm<br />
power supply arrangements, operate short-term energy markets, provide<br />
transmission service and ancillary services, and carry out other RTO functions.<br />
This section outlines the shortfalls in the current resource adequacy<br />
procedures and provides additional background to the Resource Adequacy<br />
provisions in Section X of the <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>.<br />
Resource adequacy under cost-based regulation<br />
Under a cost-of-service based regulatory framework, states and utilities<br />
developed and used procedures for decades to ensure that sufficient<br />
resources were available to meet projected customer demand. As the<br />
regulatory system evolved over time, utilities had the responsibility to plan and<br />
maintain the system to reliably meet customer demand. 112 Since utilities were<br />
generally the sole providers of electricity to customers (and were usually<br />
granted exclusive franchises to operate in their service territory), they were<br />
regulated and provided sufficient funds to operate, maintain and expand<br />
their systems, and to earn a return on their investment. States generally had<br />
the authority to regulate retail rates of their jurisdictional utilities, and<br />
approved prudent costs for new generation that was deemed used and useful<br />
for customers.<br />
Table 1 summarizes resource acquisition under cost-based vertically integrated<br />
regulation. Utilities generally took the responsibility and did the planning to<br />
acquire new resources, and had both the incentive and the obligation to do<br />
so. FERC’s authority was limited to regulation of “sales for resale” (wholesale<br />
sales) and wholesale transmission service—having only limited impact on the<br />
resource choices of vertically integrated utilities (except for the siting of<br />
hydroelectric generation facilities). In general, this arrangement worked well<br />
enough to build a great deal of the infrastructure we still use today. It was not<br />
112<br />
Many states still use this form of cost-of-service or “traditional” regulation, and likely will continue<br />
to use it for the foreseeable future. However, some states in RTO areas, and particularly<br />
states with retail access, have either modified how utilities or other LSEs acquire new resources<br />
or have shifted responsibility for new resources shifted from primarily utilities to the<br />
region or RTO markets.<br />
52 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
perfect, of course. Utilities were sometimes provided incentives to overcapitalize<br />
or over-build their systems. 113 To offset that incentive, states<br />
developed the prudent investment and used- and- useful tests. Application of<br />
these tests added to the administrative costs and may have caused some<br />
reluctance on the part of state-regulated utilities to add capacity. However,<br />
from an overall pragmatic standpoint, this system supported the construction<br />
and maintenance of a reliable and affordable system, much of which we still<br />
rely on to this day. 114<br />
Table 1.<br />
Resource adequacy under cost-based regulation.<br />
Load- Serving RTO FERC States<br />
Entities (utilities)<br />
Responsibility<br />
Authority<br />
Incentive<br />
<strong>Plan</strong>ning<br />
X<br />
X<br />
X<br />
X<br />
Resource adequacy with an RTO structure<br />
Under the current RTO system, responsibility, authority, and planning have<br />
become more fragmented among federal, state and non-governmental RTO<br />
authorities. RTOs plan for the needed resources for the system (on a systemwide<br />
basis), but they do not build anything themselves and have been highly<br />
reluctant to force anyone else to do so. States authorize projects within their<br />
jurisdiction, approving siting of generation and transmission facilities. FERC,<br />
even with its expanded role under restructuring, 115 can only provide<br />
“incentives,” but does not order (or has not yet tried to order) specific<br />
generation or transmission projects. Neither FERC nor the states usually<br />
become directly involved in constructing projects. Generators, left to their<br />
own choice, will choose technologies and fuels that make the most economic<br />
sense from their standpoint and investment time frame, which does not<br />
necessarily match the needs of the overall regional system. A generation<br />
113<br />
This includes the Averch-Johnson effect, also called “goldplating,” and “ratebase padding.”=<br />
114<br />
Perhaps one of the most famous failures of this system, one that helped usher in industry restructuring,<br />
was the nuclear power plant cost overruns of the 1970s and 1980s. However, it<br />
could be argued that this was simply the result of poor regulation, not a failure of the system<br />
itself.<br />
115<br />
As wholesale and retail restructuring has developed since the late 1980s, the amount of electricity<br />
that passes through some type of FERC-regulated control has increased. This has occurred<br />
as a result of both federal and some state legislation and regulatory changes, such as<br />
divestiture of IOU generation.<br />
www.<strong>Public</strong><strong>Power</strong>.org APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update 53
esource mix with an overreliance on one fuel may be inadequate for<br />
reliability purposes.<br />
As can be seen in Table 2, under an RTO system, responsibility, authority,<br />
incentive, and planning are divided among LSEs, RTOs, FERC, and states.<br />
The misalignment of responsibility with incentive and planning, in particular,<br />
creates a challenge that has been addressed in cumbersome and costly ways.<br />
For example, RTOs have created forward capacity markets to provide<br />
incentives to provide new generation capacity and demand response. The<br />
incentive to build has shifted from utilities to IPPs and others willing to take<br />
on the financial risk. However, these generators have no responsibility to<br />
maintain system reliability, no obligation to customers beyond their specific<br />
contract arrangements, and no system planning requirements.<br />
Table 2.<br />
Resource adequacy within RTO footprint.<br />
Load- Serving RTO FERC States<br />
Entities (utilities)<br />
Responsibility<br />
X<br />
Authority * X<br />
Incentive **<br />
<strong>Plan</strong>ning<br />
* Very limited backstop transmission siting authority for projects sited in “national interest transmission<br />
corridors,” as designated by DOE, and siting authority for hydroelectric facilities.<br />
** Only for remaining vertically integrated utilities with supply obligation to retail customers.<br />
X<br />
A similar misalignment has occurred with transmission planning and<br />
expansion. Under cost-based regulation, responsibility for grid reliability was<br />
clearly with the utility. If there were any interruptions of service, the utility was<br />
directly responsible. But this responsibility has now been shifted to RTOs.<br />
RTOs do the planning, but they do not build any transmission facilities and<br />
generally have not required their member transmission owners to do so.<br />
FERC can authorize recovery of transmission project costs if an entity<br />
proposes to build new transmission or expand its existing transmission system<br />
(including rate incentives), but has not tried to order such entities to do so.<br />
States approve the siting of new transmission lines and (in many cases)<br />
approve significant expansion of existing lines, but only rarely have required a<br />
transmission owner to expand its system. Moreover, the incentive for<br />
transmission owners that also own generation is often to not expand their<br />
facilities because it will lower prices for their generation.<br />
54 APPA’s <strong>Competitive</strong> <strong>Market</strong> <strong>Plan</strong>: 2011 Update www.<strong>Public</strong><strong>Power</strong>.org
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