Competitive Market Plan - American Public Power Association

Transcription

APPA’s
Competitive
Market Plan:
2011 Update
A Roadmap for Reforming Wholesale Electricity Markets
R
APPA’s
Competitive
Market Plan
Update 2011
A Roadmap for Reforming Wholesale Electricity Markets
June 2011
Copyright 2011 by the American Public Power Association. All rights reserved.
Published by the American Public Power Association, 1875 Connecticut Ave., NW, Suite 1200,
Washington, DC 20009-5715 • www.PublicPower.org
Acknowledgements
APPA would like to acknowledge the many individuals who provided valuable writing assistance, suggestions, comments and feedback, including Kenneth Rose,
Ph. D., Independent Consultant; Gary J. Newell, Thompson Coburn, LLP; James
A. Jablonski, Executive Director, Public Power Association of New Jersey; Robert
McCullough, McCullough Research; Paul Williams, Pennsylvania Steel & Cement
Manufacturers Coalition and Howard Spinner, Virginia State Corporation Commission. The views expressed in this paper are those of APPA alone and should not
be attributed to any individual who kindly assisted us in this effort.
Table of Contents
Executive Summary ................................................................xii
I. Introduction ............................................................................1
II. Background.............................................................................7
III. Overview of Proposed Market Structure ................................12
IV. Role of State Regulatory Agencies.........................................15
V. Bilateral Contracts .................................................................21
VI. Market Power .......................................................................27
VII. Residual Short-Term and Imbalance Services:
The Optimization Market........................................................30
VIII. RTO Operations to Support Non-Discriminatory
Transmission Access .............................................................34
IX. Renewable Energy.................................................................38
X. Resource Adequacy and Planning .........................................42
XI. Transmission Planning ...........................................................47
XII. Transition Issues ....................................................................49
XIII. Conclusion ............................................................................50
Appendix A: Division of Responsibilities for
Resource Adequacy in Current RTO Market Structures ..................52
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APPA’s Competitive Market Plan: 2011 Update
iii
Preface to the Competitive Market Plan: 2011 Update
I
n February 2009, the American Public Power Association (“APPA”)
released a proposal to reform the centralized markets run by
Regional Transmission Organizations (“RTOs”), which it called the
“Competitive Market Plan” (“CMP”). In doing so, APPA hoped to “jumpstart” a dialogue among industry participants to develop much needed
reforms to RTO-run markets. As APPA noted at the close of its proposal
(CMP at 39):
The debate should no longer be about who can best massage the
statistics or whether it is more virtuous to support “competition” or
“regulation.” Instead, the industry must work together to develop a
regulatory regime for electricity markets in RTO regions that will
truly benefit consumers, businesses and the environment. Unless
the electric utility industry and its regulators can agree on a market
design and regulatory paradigm that fairly balances the interests of
both load and generation, the industry will be condemned to
continued upheaval.
Unfortunately, the release of APPA’s CMP did not have the effect that APPA
had hoped. There was plenty of public reaction by incumbent generation
owners to the plan, but it consisted primarily of mischaracterization and
resultant dismissal of APPA’s proposal,1 and claims that APPA in fact wanted to
return to cost-of-service ratemaking or institute a “pay-as-bid” auction regime.2
Those asset owners with financial interests in maintaining the current RTO
market structure (including locational capacity markets) expended their
energies on a public relations effort to discredit the CMP and APPA, rather
than to use the CMP’s issuance as an opportunity to engage in an actual
debate about possible RTO market reforms3.
The result has been the “continued upheaval” that APPA feared. Litigation
at the Federal Energy Regulatory Commission (“FERC” or “Commission”) and
in the appellate courts regarding RTO market features continues apace, as
generator and load interests attempt to craft specific market rules and
procedures that work best for their respective interests. This new version of
the CMP updates APPA’s 2009 proposals and concerns to address several
iv
1
See, e.g., John D. Chandley and William W. Hogan, Electricity Market Reform: APPA’s Journey Down The Wrong Path, LECG, prepared for the COMPETE Coalition, April 16, 2009,
http://www.competecoalition.com/files/LECG%20study.pdf
2
For example, at page 8 of their paper, Chandley and Hogan characterize the CMP as follows:
“It is not an exaggeration, therefore, to describe this approach as akin to detailed less-thancost-of-service regulation.” APPA found these criticisms somewhat mystifying, given that the
CMP retained a “single clearing price” (SCP) auction format, and expressly called for continuation of market-based rates for bilateral contracts.
3
This was in marked contrast to some limited informal feedback from the asset owner sector
that APPA staff received, to the effect that the proposal, while not acceptable in its current
form, was indeed a thoughtful and good faith proposal worth further discussion.
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Against this backdrop of continued
inadequate market oversight, are
increasingly successful attempts by
incumbent generation owners to
develop new sources of revenue,
either through changes to current
market rules or through the creation
of new markets – almost always
over the strenuous objections of
consumer and load-side
representatives.
issues that have since risen to prominence in RTO markets, and raise
additional concerns for public power.
Events over the past two- and- a-half years continue to illustrate the absence of
adequate regulation and oversight of RTO markets by FERC. For example,
APPA’s and others’ experiences with the development of RTO performance
metrics illustrate the barriers to developing necessary measures that accurately
assess the costs and benefits of wholesale electricity markets. In response to a
2008 report by the Government Accountability Office (“GAO”)4, FERC issued
a set of proposed RTO performance metrics in February 2010, developed
largely in conjunction with the RTOs themselves. APPA and many others of
the commenters stated that the proposed performance metrics were
insufficient, primarily because they lacked essential measures of
comprehensive revenue streams from wholesale markets, generator profits
and accurate price-cost differentials.5 The final measures that FERC approved
were similar to those recommended by the RTOs and did not include such
key measures. The ISO/RTO Council then provided a report to FERC that
was essentially a recounting of the many achievements of RTOs. Hence, the
entire exercise failed to meet the original intent of the GAO’s
recommendation --— to accurately measure the validity of such claims about
market benefits.6
Against this backdrop of continued inadequate market oversight, are
increasingly successful attempts by incumbent generation owners to develop
new sources of revenue, either through changes to current market rules or
through the creation of new markets – almost always over the strenuous
objections of consumer and load-side representatives. Such enhancements of
revenue streams, however, are being implemented absent any measures to
ensure a reliable supply of power in the future to justify the payment of such
revenues.
Illustrative of these types of controversies are the proposal for scarcity pricing
4
The GAO found that “FERC has not conducted an empirical analysis to measure whether
RTOs have achieved these expected benefits or how RTOs or restructuring efforts more generally have affected consumer electricity prices, costs of production, or infrastructure investment.” Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional
Transmission Organizations’ Benefits and Performance, GAO-08-987, September 2008, p.55,
http://www.gao.gov/new.items/d08987.pdf.
5
Initial Comments of the American Public Power Association and the Electricity Consumers Resource Council, Docket AD10-5-000, Federal Energy Regulatory Commission, March 5, 2010,
http://www.publicpower.org/files/PDFs/APPAELCONAInitialCommentsAD105352010asfiled.pdf
6
ISO/RTO Performance Metrics, Commission Staff Report, Docket No. AD10-5-000, Federal
Energy Regulatory Commission, October 21, 2010, http://www.ferc.gov/legal/staffreports/10-21-10-rto-metrics.pdf.
The ISO/RTO Council subsequently issued its report on the data required by the metrics.
APPA’s response to that report is at: http://appanet.cms-plus.com/files/PDFs/APPAResponsetoRTOMetricsReport121310.pdf
www.PublicPower.org
v
in PJM, the recent battles over measures to prevent state-procured new
generation resources from participating in ISO New England’s Forward
Capacity Market (“FCM”) and PJM’s Reliability Pricing Model (“RPM”), and
the bitter disputes in the PJM Interconnection (“PJM”) regarding the specific
load forecasts that PJM uses in administering its RPM.
But even more disturbing to APPA has been the reappearance of “RTOhopping,” i.e., the practice of transmission- owning utilities with affiliates that
have unregulated generation units moving from one RTO to another to take
advantage of more lucrative payments for their generation assets. The prime
examples of this were First Energy’s migration from the Midwest Independent
Transmission System Operator (“MISO”) to PJM, proposed in August 2009
with full integration planned for June 2011, followed by Duke Energy’s June
2010 proposal to move its Ohio and Kentucky transmission and generation
assets (including jointly-owned assets) from MISO to PJM, expected to be
completed in January, 2012.7
The desire of these companies to maximize the revenues from their
unregulated generation assets is certainly understandable. And FERC’s
decision to allow such transfers,8 while deeply disappointing is also at least
understandable, given the terms of the contracts under which these
transmission owners had previously agreed to join MISO. What APPA had not
expected, however, and what it finds both profoundly anti-consumer and
deeply alarming, was the attitude of the current Chairman of FERC regarding
these transfers. As reported in the October 22, 2010 Energy Daily (at 3)
regarding the Duke Energy transfer:
FERC Chairman Wellinghoff said there was nothing wrong with
utilities switching RTOs, whether for capacity market payments or
other reasons. It is healthy for utilities to evaluate “where is the most
competitive RTO that provides them the best opportunity for their
business models to operate,” he said. And from the RTOs’
perspective, he said it was a good thing “to have other RTOs realize
that there may be another RTO that may have a superior structure
that is attracting more utilities and that they maybe should consider
changing their structure.”
When the concept of “competition” in RTO regions has devolved from
determining which RTO (and RTO market designs) can best harness
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7
FirstEnergy and Duke market integration materials are available at:
http://www.pjm.com/markets-and-operations/market-integration.aspx
8
Order Addressing RTO Realignment Request and Complaint, Dockets ER09-1589-000 and
EL10-6-000, 129 FERC ¶ 61,249 (December 17, 2009); and Order Addressing RTO Realignment Request ,Request, Dockets ER10-1562-000 and ER10-2254-000, 133 FERC ¶ 61,058 (October 21, 2010).
www.PublicPower.org
competition to deliver just and reasonable prices to consumers (as the
Federal Power Act (“FPA”) requires)9 to which RTO can offer
generation asset owners the most dollars to join their organization,
something is badly amiss. FERC regulation of RTOs under the FPA has
reached the point where, when the GAO criticized FERC for not
sufficiently evaluating and assessing RTO market performance, FERC
turned to the RTOs themselves to design “metrics” to measure their own
performance, and then adopted those metrics with very few changes,10
as described above.
Predictably, this lack of evenhandedness in balancing the interests of
generation and load in the design of RTO markets, the application of RTO
market rules, and FERC oversight of RTO markets and activities, has
resulted in consternation and restiveness among load side interests. This
has been seen most recently and clearly in the ongoing events in Maryland
and New Jersey, two states in PJM that have been required to pay high rates
in PJM’s RPM capacity auctions. Both states are located in transmissionconstrained areas of the PJM footprint. New Jersey Governor Chris Christie
signed legislation in January, 2011 providing for a “self help” remedy in the
form of mandated bilateral generation contract procurements for the
utilities that provide default retail power supply service in New Jersey, to
“anchor” the construction of new generation capacity.11 The Maryland
Public Service Commission issued a draft RFP for long-term contracts and
indicated that it is strongly considering implementing a measure similar to
New Jersey’s.12 Because a key component of these states’ plans is to bid the
resulting new generation into PJM’s capacity market auctions, thus
potentially lowering the price, owners of existing generation in PJM (PJM
Power Providers or “P3”) filed a complaint with FERC aimed at preventing
new generators with bilateral contracts from seeking to lower capacity
prices.13 Following a drop in prices in the New England capacity market,
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9
16 U.S.C. §§ 824d and 824e.
10
Notice Requesting Comments on RTO/ISO Performance Metrics, Docket AD10-5-000, 75
Fed. Reg. 7,581 (February 22, 2010); Initial Comments of the American Public Power Association and the Electricity Consumers Resource Council, Docket AD10-5-000, Federal Energy
Regulatory Commission, March 5, 2010 http://www.publicpower.org/files/PDFs/APPAELCONInitialcommentsAD105352010asfiled.pdf; and ISO/RTO Performance Metrics, Commission Staff Report.
11
New Jersey P.L.2011, Chapter 9, Senate, No. 2381, §§1,3,4 - C.48:3-98.2 to 48:3-98.4 §5 C.48:3-60.1, http://www.njleg.state.nj.us/2010/Bills/AL11/9_.PDF
12
Notice of Comment Period on Request for Proposals for New Generating Facilities , Case No.
9214, Maryland Public Service Commission, December 29, 2010,
http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfm?ServerFilePath=C:\Casenum\9200-9299\9214\\34.pdf
13
Complaint and Request for Clarification Requesting Fast Track Processing, PJM Power Providers
Group, Docket EL-20-000, Federal Energy Regulatory Commission, February 1, 2011,
http://www.p3powergroup.com/siteFiles/News/BA60285E201B5659BBD906367C86FBC9.pdf
vii
the New England generators filed a similar complaint seeking to mitigate
the effects of Connecticut’s or other states’ bidding of procured generation
as a price taker (referred to as “out-of-market resources”).14
In response to these complaints both RTOs proposed changes in their
respective capacity markets. In April 2011, FERC approved changes to PJM’s
RPM that would make it very difficult for new natural gas-fired resources
contracted for outside of RPM—- such as resources obtained under a state
procurement program like New Jersey’s or by a municipal utility for selfsupply—- to bid into the auctions at zero.15 Without the option to bid into
an auction at zero, these resources now face the danger that they would not
clear the auction, thus potentially endangering their construction. In New
England’s FCM market, FERC also approved the ISO’s development of a
minimum price requirement for bids from new resources into the capacity
market16, which will likely have an similar effect similar to the approved
RPM rule change.
APPA notes that these state actions are consistent with APPA’s
recommendation in the first edition of the CMP (at 17) that “state public
service commissions establish competitive power supply procurement
processes to develop diversified resource portfolios for incumbent [investorowned utility load- serving entities], with a significant portion of their power
supplies being obtained under longer-term contracts or owned-generation
arrangements.” APPA noted that such measures could “provide much
needed price discipline in RTO-run centralized markets.” Id. The
Commission’s recent rulings, however, seem to ensure that states will not
have the necessary tools at their disposal to assure reasonable rates for
electric power supply to their own citizens.
The frustration in Maryland, New Jersey and other states (such as
Connecticut) stems from a basic flaw in RTO-run centralized markets --—
they do not sufficiently support new generation investment but instead
overcompensate existing generators. While those supporting locational
capacity markets claimed to regulators and load-side interests that such
markets would send “price signals” to generators as to where to invest in
new generation, there has been no demonstrated relationship between
prices and investments in new resources.17 Instead, consumers have paid
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14
Motion to Intervene and Protest of the New England Power Generators Association, Docket
ER10-787-000, Federal Energy Regulatory Commission, March 15, 2010,
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=12292579
15
Order Accepting Proposed Tariff Revisions, Subject To Conditions, And Addressing Related
Complaint, 135 FERC ¶ 61,022 (April 12, 2011),
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=12617771
16
Order On Paper Hearing And Order On Rehearing, 135 FERC ¶ 61,029 (April 13, 2011),
http://elibrary.ferc.gov/idmws/File_list.asp?document_id=13909713
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literally billions of dollars through these markets to incumbent generators
with existing units. While it is true that these markets have supported
development of new demand response resources, and existing generation that
might have otherwise retired has stayed on line, it is questionable whether
these benefits justify the very high associated costs.
The failure of RTO-run centralized locational capacity markets to support
substantial new generation investment leads directly to the most important
reason why the industry now needs to engage in the “rational debate” on the
design of RTO markets that APPA had hoped to spur in 2009 --— the likely
retirement of a substantial portion of the nation’s coal-fired electric
generation fleet in the next several years. The Environmental Protection
Agency (“EPA”) is currently planning to issue a panoply of new and revised
regulations in the 2010-20 time frame, dealing with everything from NOx,
SO2 and mercury emissions to power plants’ continued use of once-through
cooling, to storage and disposal of coal ash. The cumulative effect of these
new regulations will likely make a substantial number of existing coal-fired
generation units uneconomic to operate in the future. There are many
estimates of the plant closures likely to occur, ranging from 30 to 70 gigawatts
(GW) of coal generation within the next ten years, with most estimates
trending towards the higher end of this range.18
RTO regions currently have excess generation capacity, due to the impacts of
the recession and the payments made to keep existing generation units (some
of them old and inefficient) in operation. But this situation could well
change quickly once demand begins to increase if the recession eases, and as
generation unit owners assess their units’ continued economic viability in
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17
Despite the payment of $42 billion in the first seven auctions, actual new generation net of
deactivations and retirements, has equaled just 0.5 percent of the total generation that has
cleared the market and 3 percent of the average cleared in each auction. Moreover, a recent
analysis shows that high prices within the constrained zones within PJM’s Reliability Pricing
Model have not incented greater levels of new generation clearing the RPM auctions or existing plant upgrades, demand response, energy efficiency resources, and net imports offered in
constrained zones. See Direct Testimony of James F. Wilson in Support of First Brief of the
Joint Filing Supporters, Docket ER10-787, Federal Energy Regulatory Commission, July 1,
2010, Section V, http://www.wilsonenec.com/FCM_Testimony_July_1.php
18
Studies of projected coal plant closures have been undertaken by: The North American Electric Reliability Corporation (10 - 35 GW of coal and 40 - 70 GW of all capacity by 2018), 2010
Special Reliability Scenario Assessment, October, 2010, Table IV-6,
http://www.nerc.com/files/EPA_Scenario_Final.pdf; Credit Suisse Equity Research (60 GW
of coal capacity between 2013 and 2017), Growth From Subtraction: Impact of EPA Rules on
Power Markets, September 23, 2010, http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf; The Brattle Group (50 – 66 GW of coal capacity by 2020), Potential Coal Plant Retirements Under Emerging Environmental Regulations, December 8, 2010,
http://www.brattle.com/_documents/UploadLibrary/Upload898.pdf, and FBR Capital (30 –
70 GW in the next few years), EPA regs may shut 70,000 MW of U.S. coal plants: FBR, Reuters,
December 13, 2010 http://www.reuters.com/article/2010/12/13/us-utilities-epa-coal-idUSTRE6BC3JN20101213
ix
light of these new EPA regulations. The industry and its regulators need to
start considering now how best to manage the transition to new, more
efficient and cleaner generation. Current RTO locational capacity markets,
with their relatively short (3-5 year) payout periods, simply cannot support the
required new generation investment. Something will have to give, and
relatively soon.
In short, APPA believes it is now even more important than it was in 2009 that
the industry begins the honest dialogue among its participants in RTO
regions that will be needed to manage this transition to a lower-carbon
generation future. APPA is therefore updating and re-releasing its CMP as its
contribution to the debate. It urges other sectors of the industry to see this as
a new opportunity to discuss the huge challenge before all of us, rather than
to continue the partisan battles now taking place in RTO stakeholder
processes and Commission proceedings. Such a result would be the triumph
of hope over APPA’s past experience with its release of the first version of the
CMP, but hope survives nonetheless.
x
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Executive Summary
T
his paper presents an updated version of the American Public Power
Association’s (APPA) Competitive Market Plan for reform of
wholesale electricity markets administered by regional transmission
organizations (RTOs). The plan, originally released in February 2009, was
developed based upon results of investigative studies carried out under APPA’s
Electric Market Reform Initiative (EMRI) and in consultation with APPA
members, other market participants and electricity industry experts.
APPA developed the Competitive Market Plan to attempt to remedy the
absence of meaningful competition and consumer protections under the
current RTO market model, while still assuring resource adequacy. The
changes proposed in this paper are only for regions with RTO-run centralized
wholesale power supply markets under federal jurisdiction. APPA is not
suggesting that geographic regions without RTOs adopt these proposals.
Along with the proposed reforms, APPA is also recommending a moratorium
on the development of new RTO markets, at least in the absence of strong,
widespread RTO member support for them. APPA is recommending the
following primary changes to the Day 2 RTO markets. These changes are
intended to move these markets from de facto oligopolies to more
competitive markets, while ensuring reliable electric service at just and
reasonable rates.
Power Supply Markets
• Current RTO-run energy and ancillary services real-time and day-ahead
markets would be replaced by an RTO-run “optimization” market, in
which customers can could balance supply deficiencies or excess
purchases, and generators can could sell excess generation.
• Offers to sell into the optimization market for both energy and ancillary
services would be limited to generators’ marginal costs of generation.
Generators would be required to submit their unit-specific operating
costs to the RTO market monitor in advance to provide cost support for
their offers. Prices would be set initially using a cost-based single-clearing
price mechanism, with evaluation of the results of that mechanism after
three years of operation.
• The optimization market would use a marginal cost-based, single-clearing
price model for the purpose of generation resource commitment and
dispatch.
• Generator offers into the optimization market would be made public on
the next operating day, including the identity of bidders.
• FERC-jurisdictional power suppliers entering into bilateral contracts with
load-serving entities (LSEs) in an RTO region would not be subject to
cost-based restrictions, i.e., they could use market-based rates if they have
obtained such authority from FERC. APPA recommends, however, that
FERC separately evaluate generation market power for long-term power
xii
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supply products in determining seller eligibility for market-based rate
authority.
• Generators would be subject to a must-offer requirement into the
optimization market for energy not already committed under bilateral
contracts or LSE-owned generation arrangements (subject to forced
outages, scheduled maintenance, and special rules for limited-run units).
• Demand-side resources could sell into the optimization market, but
would not be subject to a cost-based offer restriction; rather, they would
take the single-clearing price that clears the market net of the foregone
retail rate, assuming they have previously offered to reduce demand at
that price level.
Resource Adequacy
• Existing RTO-administered locational capacity markets would be phased
out over time and capacity would be supplied through bilateral contracts
entered into by LSEs with resource suppliers (both generation and
demand response), LSE-owned generation arrangements and LSEmanaged demand response.
• The RTOs would determine and implement overall resource adequacy
standards applicable to LSEs within the RTO footprint. States would have
substantial input into RTO development of regional transmission plans
and regional resource adequacy requirements.
• States would establish resource acquisition processes to secure a
diversified portfolio of generation and demand-side resources for stateregulated investor-owned utility (IOU) LSEs. In retail choice states,
competitive procurements, including consideration of both LSE selfbuild/self-supply and third-party supplier options, would be conducted
for state-regulated IOU LSEs, with an option for locally regulated LSEs to
participate.
• States and LSEs would be free to explore broader LSE resource
procurement initiatives, such as regional procurements or LSE resource
pooling.
RTO Dispatch and Transmission Operation
• RTOs would conduct centralized least-cost dispatch of generators based
on actual marginal costs. Generators and demand response providers
would be paid based upon contracted prices for quantities sold through
the bilateral market. For quantities sold through the optimization
market, generators and demand responders would receive the cost-based
market-clearing price.
• Data on bilateral contracts would be submitted to the RTO for the
purposes of market monitoring, running feasibility tests to assess
transmission adequacy, and developing regional transmission plans.
• Financial transmission rights (“FTRs”) would be allocated to LSEs. Long-
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xiii
term FTRs would also be granted to support longer-term (e.g., 10-year)
bilateral power supply arrangements and LSE-owned resources. Because
such FTRs support physical transactions, they would be exempted from
otherwise applicable collateral or margin posting requirements.
• Existing transmission rights would be maintained to the maximum extent
feasible.
• RTOs would continue to ensure non-discriminatory open access to the
transmission system.
APPA recommends as part of its Plan that FERC conduct periodic reviews of
wholesale power supply markets in RTO regions, to assess long-term price
stability, possible exercises of market power, justness and reasonableness of
rates, and reliability. To the extent that reformed RTO markets are not
making adequate progress in providing balanced incentives and benefits to
both generator and load interests, further reforms would need to be
considered.
xiv
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I.
Introduction
T
his paper presents the American Public Power Association’s (APPA)
updated plan for reform of wholesale electricity markets administered
by regional transmission organizations (RTOs). The initial plan was
developed based upon results of investigative studies carried out under
APPA’s Electric Market Reform Initiative (EMRI) and consultation with APPA
members, other market participants, and electricity industry experts. The
updated plan contains modifications suggested by two additional years of
experience with RTO-administered centralized markets.
APPA initiated EMRI in 2006 following a series of fundamental changes in the
wholesale electricity markets. The Federal Energy Regulatory Commission
(FERC) shifted its policy emphasis from ensuring non-discriminatory open
access transmission service to implementing centralized RTO-run wholesale
electric markets, with only limited wholesale price regulation. (A map of the
geographic regions covered by the RTOs is shown below.)
Meanwhile, many states implemented retail access programs to provide retail
electric consumers with a choice of electricity providers. In many of these
states, investor-owned utilities (IOUs) sold off their generating plants to third
parties (in many cases, their unregulated affiliates), which can now sell their
power at prices that are no longer tied to the costs of production, and are
subject only to limited RTO “market mitigation” rules.
Source: Federal Energy Regulatory Commission
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1
In response to growing problems that public power utilities were experiencing
obtaining power supplies in RTO regions with centralized power supply
markets, APPA launched EMRI in March 2006 to investigate restructured
wholesale electricity markets and develop needed reforms to those markets.
Under this initiative, APPA commissioned a series of studies investigating the
restructured RTO-run wholesale markets under federal jurisdiction.19 Based
on the results of these studies, APPA concluded that RTO-run centralized
wholesale markets had substantial problems, and were not yielding “just and
reasonable rates,” as the Federal Power Act (FPA)20 requires. APPA therefore
embarked on the development of potential reforms to these markets.
A fundamental reason for restructuring of electricity markets was the
expectation that the combination of open access transmission service and
RTO-operated centralized wholesale markets would promote “competition.”
This increased competition in turn would spur efficiencies and innovation,
ensure adequate supplies and, most importantly, lower rates for consumers.
But the EMRI studies and the real-world experience of consumers shows how
the opposite has occurred. These deregulated markets produced both higher
prices and higher profits than one would expect in a competitive market.
Prices exceed those prevailing in the remaining regions that have not
restructured and have instead retained cost-of-service regulation. The greatest
beneficiaries of restructuring are not consumers, or the new, innovative
companies that were promised to emerge under competition, but the owners
of large fleets of previously regulated, largely depreciated generation units.
These central concerns still remain over more than two years after the release
of APPA’s Competitive Market plan (“CMP” or “Plan”). In fact, APPA
concluded that several significant developments have necessitated updates to
the CMP. Those developments include the capacity market difficulties, the
increasing role of demand response, greater concerns over transmission costs,
planning and rate incentives, and additional and increasingly complex RTO
market proposals.
Another significant change is that the recession of the past two years has
reduced demand, which in turn lowered energy prices and lessened previous
concerns about potential supply shortages in the short term. Because these
price drops were the result of external economic factors, they do not by
themselves affirm or negate the success of the markets in providing benefits
for consumers. The absence of a connection between RTO markets and
recession-induced price decreases, however, have has not stopped supporters
2
19
The results of these studies are available on the EMRI section of APPA’s Web site at: www.PublicPower.org/emri.cfm
20
FPA Sections 205 and 206, 16 U.S.C. §§ 824d, 824e.
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of the markets from citing these lower prices as evidence of the
“competitiveness” of the markets.21
While wholesale energy prices fell in 2009 and began to rebound in 2010,
overall retail prices in both in regulated and deregulated states have
continued to increase. But prices in deregulated states within RTO regions
have been 50 percent greater than regulated states in the past two years.22
Part of the reason for this wholesale/retail disparity is the many nongeneration costs that directly affect retail rates, such as local distribution costs.
Another factor is that indices of wholesale energy prices by themselves do not
provide a complete picture of all components of generation costs. Sources of
wholesale market revenue to generators include capacity market, ancillary
service, and uplift payments, as well as revenue from bilateral contracts, such
as those arranged for provision of standard offer service.
It is highly likely that the declines in wholesale prices reflect just a temporary
drop that affects primarily the energy spot markets, and not other RTO
markets. First, an increasing amount of revenue has been flowing through the
capacity markets, and prices in the constrained areas in the PJM23 and NY
ISO24 locational capacity markets have been increasing. Second, the pending
closure of some coal plants, especially in RTO regions, in response to EPA
21
For example, the Electric Power Supply Association (EPSA), in a statement on the 2009 market monitor reports, asserted that: “The annual reports note that the organized wholesale
markets are appropriately reflecting dramatically lower fuel prices with electricity prices dropping by roughly 50 percent from 2008 levels across the markets. The reports once again underscore the benefits to consumers of independent operation of the transmission system and
markets that are quickly responsive to lower costs.” Organized Wholesale Markets Are Competitive and Delivering Benefits to Consumers, EPSA PowerFact, August 25, 2010,
http://www.epsa.org/forms/documents/DocumentFormPublic/view?id=16CC400000002.
In 2009, Joel Malina, Executive Director of COMPETE, stated that: “In competitive electricity
markets all over the country electricity prices are on the downturn. This evidence should put
to rest the superficial arguments suggesting that competitive markets aren’t working.” Rates
Continue to Decrease in Competitive Markets, Including Ohio, Massachusetts, Pennsylvania,
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
www.PublicPower.org
22
Retail Electric Rates in Deregulated and Regulated States: 2010 Update, APPA, March 2011,
http://www.publicpower.org/files/PDFs/RKWFinal2010.pdf
23
As determined by the capacity market auctions, prices in the transmission-constrained areas
are scheduled to increase in June 2012, and again in June 2013, more than doubling the June
2011 price. See PJM’s Base Residual Auction Results at http://www.pjm.com/markets-and-operations/rpm/rpm-auction-user-info.aspx#Item06.
24
Capacity prices in New York City increased by 92 and 57 percent in the second and third
quarters of 2010 and compared to the same quarters for 2009, while falling slightly in other
areas. Quarterly Report on NY ISO Electricity Markets, Second Quarter 2010, July 2010, p. 3,
Third Quarter 2010, October 2010, p. 3; http://www.nyiso.com/public/webdocs/documents/mmu_quarterly_reports/2010/NYISO_Quarterly_Report_2010Q2.pdf; and
http://www.nyiso.com/public/webdocs/documents/mmu_quarterly_reports/2010/NYISO_
Quarterly_Report_2010Q3.pdf
3
regulations is likely to constrain supply and result in the dispatch of more
expensive power plants, increasing both energy and capacity prices.25
Transitory price decreases should not affect conclusions about the overall
costs and benefits of the RTO-operated electricity markets. Evaluating costs
and benefits requires a determination of whether prices produced in the
RTO-operated markets are what one would expect to see from a truly
competitive market, as indicated by prices being equal to (or at least close to)
the actual costs of production, accounting for a contribution to fixed costs. In
contrast, two APPA analyses showed that high profits continued in 2009 and
2010 for the largest owners of unregulated generation in PJM, as measured by
net operating income and returns on equity. These high profits indicate that
rates remain substantially above the costs of production of electricity incurred
by these merchant generators.26
The impact of RTO markets on generator profits, and in turn on the
consumer, varies depending upon whether the state regulatory regime
employs retail choice or vertical integration with an obligation to serve
customers. For example, in the Midwest region almost all LSEs fall into this
second category. For these generation-owning utilities with an obligation to
serve, the excess profits recovered by baseload generators in the RTOoperated markets are passed back to the consumer, not retained by
shareholders as profit. Two companies owning merchant generation located
within the Midwest ISO, First Energy and Duke Energy, are in the process of
moving their transmission and generation assets from MISO to PJM.27 The
greater capacity prices in PJM’s market will provide a more lucrative earnings
opportunity for these companies. In an apparent attempt to avoid future
departures, and support the entrance of the Entergy operating companies,
MISO is in the process of developing a proposal for a centralized forward
4
25
Credit Suisse projects that the likely supply constraints resulting from the coal plant closures
would increase power prices by at least $5 per MWh in PJM-West and MISO, as well as putting
upward pressure on capacity prices. Growth From Subtraction: Impact of EPA Rules on Power
Markets, Credit Suisse Equity Research, September 23, 2010, pp. 47-48,
http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf
26
2009 Financial Performance of Owners of Unregulated Generation: High Profits Earned in
Restructured Wholesale Electricity Markets During the Recession, APPA, May 2010,
http://www.publicpower.org/files/PDFs/2009FinancialPerformanceMay2010.pdf; and Financial Performance of Owners of Unregulated Generation in PJM: 2010 Update, www.publicpower.org/files/PDFs/FinancialPerformance2010UpdateMay2011.pdf
27
FirstEnergy Service Company’s move into PJM is planned to be completed by June 1, 2011,
and will include the American Transmission Systems, Inc. (ATSI) transmission assets, the regulated distribution utilities (The Cleveland Electric Illuminating Company, Ohio Edison
Company, The Toledo Edison Company, and Pennsylvania Power Company) and the merchant generation owner, FirstEnergy Solutions. Duke Energy’s move is planned for January 1,
2012, and includes the transmission assets of Duke Energy Ohio, Inc. and Duke Energy Kentucky, Inc., as well as the Duke Energy generation assets. See the Market Integration section
of PJM’s web site at http://www.pjm.com/markets-and-operations/market-integration.aspx
www.PublicPower.org
capacity market, resembling PJM’s Reliability Pricing Model.28
APPA developed its CMP to attempt to remedy the absence of meaningful
competition and consumer protections under the current RTO market
model, while still assuring resource adequacy. The changes proposed in this
paper are only for regions with RTO-run centralized wholesale power supply
markets under federal jurisdiction. APPA is not suggesting that geographic
regions without FERC-jurisdictional RTOs adopt these proposals. Along with
the proposed reforms, APPA is also recommending a moratorium on the
development of new RTO markets, at least in the absence of strong,
widespread RTO member support for them.
Although the changes APPA proposes would require a lengthy
implementation period, APPA made substantial efforts to work within the
existing RTO structure. Current RTO market structures are extremely
complicated and cannot be easily modified, due in large part to a stakeholder
process that is heavily influenced by generation owners. To the extent that
current features of RTO markets are maintained in the CMP, this should not
be construed as an APPA endorsement of such features, but rather
recognition that a complete overhaul of the existing markets would be very
difficult to accomplish.
Goals of the Competitive Market Plan
APPA intends that its Plan would produce the following outcomes:
• Increase the availability of long-term bilateral power supply contracts
(e.g., a 10-year term) and opportunities for LSE-owned generation, in
turn enhancing the viability of financing new generation and renewable
energy technologies.
• Reduced opportunities for market participants to exercise market power.
• Transmission planning and construction processes that support longterm bilateral contracts/generation ownership and the new generation
resources developed with the support of such power supply
arrangements.
• Greater opportunities for LSEs to hedge congestion and reduced
speculative opportunities for financial-only market participants.
• Reduced power supply price volatility and wholesale electricity rates that
better comport with the just and reasonable standard of the Federal
Power Act.
28
www.PublicPower.org
Midwest ISO Resource Adequacy Enhancements Proposal, Supply Adequacy Working Group,
Midwest ISO, December 9, 2010, https://www.midwestiso.org/Library/Repository/Meeting%20Material/Stakeholder/SAWG/2010/20101209/20101209%20SAWG%20Item%2003
%20Midwest%20ISO%20RA%20Enhancement%20Proposal.PDF; and other materials from
the MISO Supply Adequacy Working Group meetings, https://www.midwestiso.org/Library/MeetingMaterials/Pages/SAWG.aspx
5
• Resource adequacy standards, increased bilateral contracting, use of
owned generation, and an optimization market that together would
improve the reliability of electricity service.
6
www.PublicPower.org
II. Background
T
his plan originated in a proposal, first presented in APPA’s
February 2008 paper “Consumers in Peril,”29 to restructure
current “Day Two” RTOs as “Day One” RTOs.30 After careful
investigation and refinement of this concept, APPA decided that the best
approach would be to develop a hybrid of the best elements of both RTO
structures. Current Day Two RTOs operating in the United States include
the PJM Interconnection (“PJM”), the Midwest Independent Transmission
System Operator (“MISO”), ISO-New England (“ISO-NE”), and the New
York Independent System Operator (“NYISO”) and the California ISO
(“CAISO”). The Southwest Power Pool (“SPP”) is currently the only
example of a FERC-approved Day One RTO.31 For the remainder of this
paper, the term RTO will be used to refer to a Day Two RTO. This paper
will not delve into all of the problems LSEs have experienced with RTOs.
To briefly summarize, the CMP was developed to remedy the most
problematic aspects of RTO markets at the time, which are briefly outlined
below and discussed in greater detail in Consumers in Peril:32
• The use of bid-based offers into the day-ahead and real-time markets
provides opportunities for potential exercises of market power through
the use of strategic bidding strategies, and the absence of any real
relationship between prices and marginal costs reduces the price
transparency needed for true competition.
• The lucrative nature of the RTO-operated energy and capacity markets
had has produced supra-competitive profits and has made incumbent
sellers reluctant to enter into long-term bilateral power supply contracts
at prices not directly linked to RTO-run spot market prices (plus
substantial premiums in some cases). While new market entrants are
now interested in long-term power supply contracts to support the
financing of their generation projects, it is difficult for them to find
www.PublicPower.org
29
“Consumers in Peril: Why RTO-Run Electricity Markets Fail to Produce Just and Reasonable
Electric Rates,” APPA, February 2008 available at:
http://www.publicpower.org/files/PDFs/ConsumersinPeril.pdf . The policy recommendation to restructure RTO markets appears in Section 5, which is the focus of this document.
30
A “Day Two” RTO refers to a market structure where the RTO manages the transmission grid
within its footprint to ensure non-discriminatory transmission access and reliability, runs centralized markets for energy (day-ahead and real-time) priced using locational marginal pricing concepts, and provides financial transmission rights (FTRs) to hedge the associated
transmission congestion costs. Depending on the market design, a Day Two RTO may also
run centralized markets for ancillary services and capacity. A Day One RTO does not administer centralized spot markets, except perhaps for a balancing market, but does oversee management of the transmission grid for reliability and open-access purposes.
31
SPP is has announced its intent to implement a Day Two market, and the most recent estimate for implementation is March 2014. Integrated Marketplace Project Milestones, SPP Market Working Group, October 25, 2010,
http://www.spp.org/section.asp?group=1985&pageID=27
32
See Ch. 4 of “Consumers in Peril: Why RTO-Run Electricity Markets Fail to Produce Just and
Reasonable Electric Rates.”
7
LSEs in restructured states that are able and willing to enter into longterm contracts to support such projects, due to the shorter-term nature
of retail default supply regimes.
• Excessive reliance by RTOs on often ineffective market and pricing
signals and incentives to address transmission congestion and
anticipated capacity shortfalls has substantially increased costs to
electric consumers over what they would otherwise be.
• Locational capacity markets are producing high capacity prices and
opportunities for economic withholding, leading to substantial
overpayments for capacity retention and additions.
• Hedge funds, investment banks and other financial entities are
participating in RTO markets through Financial Transmission Rights
(“FTR”) auctions and virtual bids in spot markets, potentially increasing
costs to consumers through their speculative activities.
Moreover, since the issuance of APPA’s original CMP, actions by states to
find alternative means to the centralized capacity markets to develop
needed generation at reasonable prices have elicited vehement protests by
generators, resulting in FERC-approved changes to the capacity market
rules to prevent such state actions.
All of these problems point to markets that are inherently uncompetitive,
requiring significant interventions from market monitors and other
regulators to keep generators from exercising overt market power and
raising prices even during non-peak periods. Even with aggressive market
monitoring, these RTOs’ market rules and institutions have created a
system where the benefits of competition flow disproportionately to
owners of existing generation.
FERC and the RTOs have been largely unwilling to investigate and
acknowledge the problems with these markets.33 In response to a 2008
Government Accountability Office (“GAO”) report, FERC issued a set of
proposed RTO performance metrics in February 2010. In its comments on
these metrics, filed jointly with the Electricity Consumers Resource
Council, APPA stated that the proposed “performance metrics shed little
8
33
For example, a 2008 study by the Government Accountability Office (GAO) found that
“FERC has not conducted an empirical analysis to measure whether RTOs have achieved
these expected benefits or how RTOs or restructuring efforts more generally have affected
consumer electricity prices, costs of production, or infrastructure investment.” Electricity Restructuring: FERC Could Take Additional Steps to Analyze Regional Transmission Organizations’ Benefits and Performance, p.55, GAO-08-987, September 2008 (“GAO Report”),
http://www.gao.gov/new.items/d08987.pdf.
34
Initial Comments of the American Public Power Association and the Electricity Consumers
Resource Council, Docket No. AD10-5-000, Federal Energy Regulatory Commission, March 5,
2010. www.publicpower.org/files/PDFs/APPAELCONInitialCommentsAD1OS352010asfiled.pdf
www.PublicPower.org
light on whether such prices are just and reasonable and reflect levels that
would be produced in a truly competitive market.”34 Almost half of the
commenters stated that the performance metrics were insufficient.35
While the Commission on October 21, 2010, issued a Staff Report on
ISO/RTO Performance Metrics,36 the metrics set out in that report
continued to omit the fundamental measure requested by APPA and
others -- the profits earned by generators from all wholesale electricity
markets. In response to the FERC staff metrics, the ISO/RTO Council
provided a report to FERC that was essentially an assertion of the many
achievements of RTOs, a number of which were unrelated to or
unsubstantiated by the actual data presented in the rest of the report.37
FERC then issued a Report to Congress essentially summarizing the RTOs’
own reports.38
In the continued absence of any meaningful FERC investigation into the
operation of RTO-run centralized markets and their benefits to
consumers, each difficulty in the markets is met by the RTOs themselves
with a new, increasingly complicated market and/or pricing incentive,
often approved by FERC without sufficient scrutiny of how or whether this
new feature will achieve the desired goals. For example, in the face of
looming shortfalls in generation capacity, RTOs in the past responded only
to complaints of generators that RTO mitigation rules and protocols
prevent them from earning sufficient revenues in the energy market to
recover the fixed costs or going-forward costs of generating units (the
“missing money” problem). In response, the RTOs have created a number
of secondary markets, such as those for locational capacity and ancillary
services. A number of reports have challenged the validity of the missing
money problem and suggested that these secondary markets are even less
35
Reply Comments of the American Public Power Association and the Electricity Consumers
Resource Council, Docket No. AD10-5-000, Federal Energy Regulatory Commission, March
19, 2010,
http://www.publicpower.org/files/PDFs/APPAELCONAD105ReplyComments31910asfiled.p
df
36
ISO/RTO Performance Metrics, Commission Staff Report, Docket No. AD10-5-000, Federal
Energy Regulatory Commission, October 21, 2010, http://www.ferc.gov/legal/staffreports/10-21-10-rto-metrics.pdf.
The ISO/RTO Council subsequently issued its report on the data required by the metrics.
APPA’s response to that report is at: http://appanet.cms-plus.com/files/PDFs/APPAResponsetoRTOMetricsReport121310.pdf
www.PublicPower.org
37
http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3003829518EBD%7D/2010%20ISO-RTO%20Metrics%20Report.pdf. For APPA’s response to
the report, see APPA Calls Recently Released ISO/RTO Market Report ‘Inadequate’, News
Release, December 13, 2010, http://appanet.cms-plus.com/files/PDFs/APPAResponsetoRTOMetricsReport121310.pdf
38
Performance Metrics for Independent System Operators and Regional Transmission Organizations, Federal Energy Regulatory Commission, Office of the Chairman, April 2011,
http://www.ferc.gov/industries/electric/indus-act/rto/metrics/report-to-congress.pdf
9
competitive than RTO-run spot energy markets.39 And despite the very
substantial dollars paid, these markets have resulted in few new generation
projects.
The most recent example of yet another layer of a complex pricing incentive
with the potential to yield lucrative results for generators rather than
reliability benefits is PJM’s June 2010 “scarcity pricing” proposal.40 Under this
proposal, energy prices could climb up to $2,700 per megawatt-hour
(compared to the current cap of $1,000) during times when operating
reserves dip below a threshold level. PJM’s Market Monitor described the
proposal as a “proposed radical alteration of the PJM market design in a
manner that would raise the overall price of wholesale electric service in PJM
with no corresponding benefit to its wholesale customers.”41 Further
complicating the array of new markets is that they are increasingly linked to
each other. Scarcity pricing, for example, would directly impact both the
locational capacity and reserves markets.
FERC also ordered in Docket No. RM10-17-00042 that RTOs are to pay
demand response resources bidding directly into RTO wholesale energy
markets the “full LMP” (locational marginal price) in all hours, as long as
such dispatch of the demand resource passes a net benefits test. This payment
of LMP has no offset to reflect the fact that demand response resources are
avoiding the cost of purchasing power from their LSEs, even though these
LSEs are incurring the costs to stand ready to serve the retail customers
participating in such wholesale demand response bids. Aside from the
10
39
See, for example, T. Mount, Investment Performance in Deregulated Markets for Electricity:
A Case Study of New York State, report for APPA, September 2007. Available at:
http://www.publicpower.org/files/PDFs/StudyMountEMRIreportNYISOCapacity09%2D07.p
df. Also, see James Wilson, Raising the Stakes on Capacity Incentives: PJM’s Reliability Pricing
Model, report for APPA, February 2008, available at
http://publicpower.org/files/PDFs/RPMreport2008.pdf. Reports from the PJM market
monitor also concluded that the capacity markets are often not competitive. For example,
Joseph Bowring, PJM’s market monitor, concluded that “the market design for capacity leads,
almost unavoidably, to structural market power in the capacity market. The capacity market is
unlikely ever to approach a competitive market structure in the absence of a substantial and
unlikely structural change that results in much greater diversity of ownership.” Analysis of the
2013-2014 RPM Base Residual Auction, Monitoring Analytics, July 14, 2010, p.1,
http://www.monitoringanalytics.com/reports/Reports/2010/Analysis_of_2013_2014_RPM_
Base_Residual_Auction_20100714.pdf
40
PJM Interconnection, L.L.C., Compliance Filing, Docket ER09-1063-006 , Federal Energy Regulatory Commission, June 18, 2010,
http://elibrary.ferc.gov/idmws/file_list.asp?accession_num=20100621-0201
41
Protest and Compliance Proposal of the Independent Market Monitor for PJM, Docket ER091063-006 , Federal Energy Regulatory Commission, July 18, 2010, p. 2,
http://elibrary.ferc.gov/IDMWS/File_list.asp?document_id=13832963,
42
Order No. 745, Demand Response Compensation in Organized Wholesale Energy Markets,
134 FERC ¶ 61,187, 76 Fed. Reg. 16,658 (March 24, 2011). The net benefits test calls for the
full LMP to be paid to demand response resources when the cost of payments to demand response is outweighed by the benefits of the decrease in LMP as a result of reduction in load.
www.PublicPower.org
difficult measurement and verification issues that payment of such dollars to
entities that are reducing their retail energy usage raises, there is the separate
question of whether the availability of such dollars at wholesale undermines
retail efforts to implement demand response using time-differentiated prices,
and the substantial investments, e.g., smart grid installations, that often
accompany such efforts. While APPA certainly understands the desire to
foster demand response as a resource, retail and wholesale programs and
pricing need to be harmonized, not enacted in a piecemeal and conflicting
fashion. Moreover, the implications of relying on increasingly high levels of
demand response to provide the equivalent of generation capacity needs to
be fully understood, given the absolute need to maintain reliable RTO
operations.
The layering on of new markets and pricing policies has created such a level
of complexity that highly sophisticated entities have a built-in advantage in
participating in RTO markets. Such complexity also impairs transparency and
makes the task of market monitoring more difficult.
www.PublicPower.org
11
III. Overview of Proposed Market Structure
A
•
•
•
•
PPA developed its Competitive Market Plan to support the following
design goals:
• Reduced opportunities for the exercise of market power, and
sufficient data transparency to identify market power abuses;
For load not served by owned resources, an increased emphasis on longterm bilateral contracts (e.g., 5-10 years or longer) to support reliable
service to customers at reasonable rates and to finance needed new
generation and demand response resources, with minimal dependence
on short-term energy markets to obtain power supplies;
Provision of open-access non-discriminatory transmission service;
Transmission and resource planning to meet reliability and
environmental stewardship goals over time at the lowest reasonable cost
from the most feasible set of resources, rather than merely to support
long-distance, short-term transactions or the agendas of particular
transmission or generation project developers; and
Minimization of market and operations complexity, and maximum
procedural and data transparency for market participants, regulators and
the general public.
To accomplish these goals, APPA recommended that current RTO Day Two
markets be reformed to retain the beneficial functions of RTOs, while
modifying or phasing out problematic market design features. Under this
plan, an RTO would offer transmission service to support open access to the
transmission system, operate a marginal cost-limited single-clearing price
“optimization market” for short-term procurement of energy and ancillary
services, implement RTO-determined region-wide resource adequacy
requirements, and plan for transmission facilities and service needed to
support LSE-owned and contracted-for resources. Longer-term bilateral
agreements between LSEs and generators/demand-side providers and LSEowned resource arrangements would be the primary methods of procuring
resources.
APPA concluded, based on communications with APPA’s members and
observations of the current markets, that it would be very difficult to radically
overhaul the current RTO-operated markets. In particular, it would be
difficult to revert to the use of physical transmission rights rather than
financial rights. To do so would upend numerous contracts and arrangements
to serve load, as well as planned and ongoing construction of power plants.
APPA’s Competitive Market Plan therefore would include the following
features, which are described in greater detail in this paper:
• RTO operation of a residual, marginal cost-limited single-clearing price
“optimization market” for balancing and short-term procurement of
energy and ancillary services, but without limitations on the quantity of
12
www.PublicPower.org
power sold through the optimization market.
• Use of longer-term bilateral agreements and resource ownership as the
primary methods of obtaining generation and demand-side resources.
• Power procured through the bilateral contracts would continue to clear
through the RTO-operated energy markets, with a financial settlement
for the differences made by the contract parties outside of the RTO
market.
• Non-discriminatory open access to the transmission system and provision
of long-term transmission rights to support LSE resource arrangements.
• Provision of data on generator costs and optimization market offers to
the public on a timely basis.
• Centralized RTO dispatch of generation, using actual marginal-cost data
as the basis of dispatch, rather than bid-based offers, but retaining the
single-clearing price feature.
• Phase-out of existing locational capacity markets over a time period long
enough to ensure that existing obligations are fulfilled.
• Phase-in of RTO-determined resource adequacy requirements for all
LSEs to be met through portfolios of generation, demand response and
energy efficiency resources.
• State supervision of resource procurement for state-regulated IOU LSEs
in retail access states, with emphasis on developing a diverse portfolio of
resources of varying fuel types and terms.
• Public reporting by FERC of RTO market performance metrics that at a
minimum include data on revenues earned and costs incurred by
generation units.
The purpose of emphasizing longer-term bilateral contracts and generation
ownership arrangements is to make the market structure more compatible
with current financial realities and longer-range system planning for
generation, transmission and demand response. Under the current market
structure, investment decisions must be based on far-forward expectations of
spot and capacity market prices, the volatility of which may discourage the
development of appropriate risk-management products and practices.43
The RTO would continue to act as a regional transmission-management
entity, but its operations would shift in focus to supporting bilateral resource
contracts and owned- generation arrangements, rather than operating
expansive centralized spot markets. The RTO would continue to dispatch
generation centrally to ensure open-access and reliability, but would provide
long-term transmission rights (“LTTRs”) more compatible with the use of
bilateral and resource ownership arrangements for long-term power supply.
The RTO would perform residual centralized real-time optimization market
43
www.PublicPower.org
L.B. Lave, J. Apt and S. Blumsack, Deregulation/Restructuring Part I: Re-Regulation Will Not
Fix the Problems, Electricity Journal 2007, 20 (8), pp. 9 – 22.
13
functions. APPA expects, however, that under its proposal, sales in the
optimization market would constitute a smaller portion of total energy sales.
Finally, the distribution side of the market would not change substantially,
with regulated distribution utilities still responsible for physical delivery of
power supplies to end-use customers.44
The reforms laid out in this paper could not be implemented within a short
time frame. It has been over 10 years since Order No. 2000 was issued,
encouraging the initial formation of RTOs. The problems with RTO markets
have been building ever since, and would take a number of years to address.
In recent years, RTO markets have proliferated, increasing the complexity of
undertaking any reforms. A number of complex FERC proceedings would be
required to develop and approve tariff changes for each RTO, many of which
are likely to be contentious. Moreover, there are differences among the RTOs
themselves. Implementation of the APPA Plan would therefore need to be
tailored on an individual RTO basis. But the longer the industry and FERC
wait to begin this important task, the longer it will be before consumers begin
to see the benefits of the needed market reforms.
APPA recommends as part of its Plan that FERC conduct periodic reviews of
wholesale power supply markets in RTO regions, to assess long-term price
stability, possible exercises of market power, justness and reasonableness of
rates, and reliability. These reviews should encompass a wide array of
performance metrics, including measures of profitability.
44
14
Third-party retail suppliers may have a diminished role in the new market regime. Retail access policy decisions should still be up to individual states, but competitive retail suppliers
would need to be willing and able to meet longer-term resource adequacy requirements applicable to LSEs, either directly or through arrangements with third parties.
www.PublicPower.org
IV. Role of State Regulatory Agencies
W
hile much of this paper is focused on the policy decisions FERC and
the RTOs must make regarding wholesale market design and
regulation, needed reforms to the wholesale markets cannot be
accomplished without parallel changes to retail choice state policies. As
discussed earlier, there is a significant difference in the degree to which
consumers are impacted by RTO markets in states where utilities are vertically
integrated and those where the bulk of the power is generated by unregulated
power plants. In fact, events over the last few years make clear that problems
in the retail access states are the most likely impetus for needed market
reforms. Since states are closest to retail customers and see the adverse
impacts of federal RTO policies first hand, they are more likely to seek
reforms to improve RTO operations in their regions. These recommendations
are therefore directed at retail access states with a high percentage of power
from merchant generation. Retail access policies would still be left up to
individual states, but, under the APPA Plan, competitive LSEs providing
service in retail access states would have to meet the more rigorous resource
adequacy requirements applicable to LSEs, either directly or through
arrangements with third parties.
The power purchases that incumbent non-vertically integrated IOU LSEs in
retail access states make to support default supply service to retail customers
that have not chosen a third-party supplier (often called “standard offer
service” or SOS) have a substantial impact on wholesale market prices. In
such states, the power supplies that incumbent LSEs use to provide SOS are
typically purchased through state-run auctions for relatively short-term
(usually two-to four-year) contracts.45 As discussed later in this plan, the prices
offered under these contracts are frequently based on forward projections of
the prices likely to be set in RTO-run centralized spot markets. The relatively
short-term nature of the SOS procurement auctions have therefore actually
reinforced the connection between RTO-run spot market prices and bilateral
contract prices, rather than allowing bilateral contract prices to act as a check
on spot market prices. Generators selling under SOS auction contracts
effectively obtain the benefits of RTO spot market pricing, as well as
additional risk premiums included in the auction prices. Given such profit
opportunities, it is not surprising that other LSEs and large end users
attempting to procure wholesale power supplies through bilateral contracts,
such as public power systems and large industrials, would find it difficult to
obtain reasonably priced contracts.
45
www.PublicPower.org
One such auction is the New Jersey Basic Generation Service or BGS auction. Contracts for
residential and small business customers last three years with one-third of load procured each
year, and commercial and industrial customers are supplied in one-year contracts. A full description of the BGS auction regime can be found at: State of New Jersey, Board of Public
Utilities, BGS Auction, http://www.state.nj.us/bpu/divisions/energy/bgs.html
15
Changes in state policies that would allow their incumbent LSEs to purchase
or build generation facilities or enter into longer-term (e.g., 5-15 year) power
supply arrangements to provide SOS to their retail customers would impose
needed discipline on the wholesale market.
An essential component of APPA’s Competitive Market Plan is a strong
recommendation that state public service commissions establish competitive
resource procurement processes to develop diversified resource portfolios for
incumbent IOU LSEs that no longer have the obligation to serve customers,
with a significant portion of their power supplies being obtained under
longer-term contracts or owned-generation arrangements. These measures
could provide much needed price discipline in RTO-run centralized markets,
as well as a steady revenue stream to support construction of new generation
resources and investment in demand response technologies.46 Such a statelevel procurement process is described in greater detail in Section X
(Resource Adequacy and Planning).
APPA recognizes that state commissions may have some reluctance to require
the LSEs they regulate to lock-in long-term prices, for fear that prices will
subsequently decline, leaving LSEs on the “wrong side” of current market
prices. Long-term contracts entered into by many utilities in the 1970s and
1980s were later found to be “above-market,” causing the payment of stranded
costs following state-level deregulation.47 The Competitive Market Plan
contains two recommendations to hedge the potential long-term contract risk.
The first is to procure a portfolio with a blend of long-, medium- and shortterm resource contracts to minimize the price risk associated with any one
resource arrangement. Longer-term contracts could be targeted to new
generation units and resource arrangements that require more revenue
certainty to secure financing and ensure a reasonable cost of capital, while
medium- and short- term arrangements could be targeted to older, largely
46
A 2008 report by the Maryland Public Service Commission finds that long-term power purchase agreements (PPAs) would encourage needed generation and lower wholesale market
costs. Final Report of the Public Service Commission of Maryland to the Maryland General
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
%20the%20MD%20General%20Assembly.pdf
In a Connecticut proceeding, Levitan & Associates found that “[n]ew generation in Connecticut anchored under a long-term contract should thus help put downward pressure on energy
prices in Connecticut,” and that “[f]uel diversity objectives in New England could be promoted through long term contracts.” Comments Of Levitan & Associates, Inc., DPUC Development and Review of Standard Service and Supplier of Last Resort Service Docket
06-01-08PH01 Jan. 30, 2007, pp. 4 and 11, http://www.dpuc.state.ct.us/dockhist.nsf/
f068a53a31082a558525664e00498f40/3bf2ed4f4da8cfe3852573f000640cf6/$FILE/LAI%20C
omments%2030Jan07.pdf
47
16
Electric Utilities: Deregulation and Stranded Costs, Congressional Budget Office, October
1998, http://www.cbo.gov/ftpdocs/9xx/doc976/stranded.pdf. Of course, in many cases the
assets in question were eventually found to be “in the market” rather than “above-market.”
www.PublicPower.org
depreciated units and other resources that do not demand high up-front
capital commitments. The second recommendation, discussed below, is to
allow incumbent utilities to construct their own power plants on a going
forward basis if there are insufficient or unacceptable options put forth by
third-party generators.
As part of such an improved SOS resource procurement process, retail access
states should allow their incumbent IOU LSEs to consider “self-builds” and
“self-provision” of demand response as resource options. In many retail choice
states, incumbent LSEs are currently prohibited from building new
generation (except perhaps through an unregulated affiliate), even though
they still bear responsibility for providing SOS service. The availability of selfbuild options brings additional competitive discipline to bear on third-party
suppliers submitting generation supply offers in power supply procurements.
While concerns about pending generation supply shortages that were
prevalent in 2006 and 2007 have been mitigated by increased demand
response and recession-induced load decreases,48 such state-implemented
measures to provide additional sources of supply when needed would also
reduce potential for tighter supply conditions in the future that could drive
up prices,49 especially those resulting from the potential closure of coal plants
as will be discussed later in this document.
Recent experience with state legislative and regulatory actions to procure new
generation resources outside of the centralized capacity markets, and
encourage the development of cleaner and more efficient generation,
illustrate potential difficulties for undertaking such efforts. These actions,
while beneficial to the states’ interests in protecting consumers, improving
reliability and reducing power plant emissions, also adversely affect the profits
of incumbent power plant owners. As a result, such merchant generators have
successfully exerted pressure on the RTOs and FERC to change the rules
governing the capacity markets to prevent such state measures in the future.
One of the earlier undertakings began with Connecticut’s signing of longterm contracts with a number of new peaking units in accordance with
www.PublicPower.org
48
These changes can be illustrated by the findings of the Long-Term Reliability Assessment
(LTRA) issued annually by the North American Electric Reliability Corporation (NERC). In
the 2007 LTRA, NERC stated that: “Long-term capacity margins are still inadequate.” In the
2010 LRTA, released in October 2010, NERC concluded that “NERC Regions and subregions
have sufficient plans for capacity to meet customer demand over the next ten years.”
http://www.nerc.com/page.php?cid=4|61
49
A 2009 Wall Street Journal article notes: “Some wonder whether the deregulated markets of
the Eastern U.S., Midwest, Texas and California will be especially hard hit if demand comes
roaring back. That’s because utilities in these markets no longer are required to build new resources. It’s left up to the power generators to determine when the market conditions are
ripe.” Rebecca Smith, “Electricity Prices Plummet,” The Wall Street Journal, August 12, 2009,
http://online.wsj.com/article/SB125003563550224269.html, Subscription required.
17
legislation passed in 2005 and 2007 aimed at lowering congestion costs,
spurring new generation, demand response and renewable energy.50 When
ISO New England’s Forward Capacity Market (FCM) auctions began in early
2008, Connecticut bid contracted units into the auction as “price takers.”
More recently, in early 2011, Governor Christie of New Jersey signed
legislation and the Maryland Public Service Commission issued a draft RFP
for the procurement of new generation resources through long-term
contracts with the distribution utilities.51 In both cases, the states were
responding to the absence of new, efficient and cleaner generation resulting
from PJM’s RPM and concerns about future reliability. The contracted-for
capacity would then be bid into the capacity markets at zero or a very low
price to ensure that it would clear the auction, with the secondary benefit of a
lower capacity price for all capacity that cleared the auction.
In New England, the capacity price has reached the floor price in the last
auction and the lower bound of the price collar in the prior three auctions.52
While it is not certain that the Connecticut resource bids directly caused the
low capacity price, which may have resulted more from the large quantity of
demand response bids, the coincidence of these state-procured resources and
the low price spurred a complaint with FERC by the merchant generator
association (the New England Power Generators Association or “NEPGA”).
Similarly, in response to concerns over a possible future reduction in capacity
market revenue from the New Jersey and Maryland actions,53 the PJM Power
Providers or “P3” filed a complaint with FERC. In response to these
complaints, both RTOs proposed changes in their capacity markets to prevent
the price-lowering effects of such separately procured resources.
In April 2011, FERC issued its orders in both dockets.54 At the core of each
50
Public Act 05-01, An Act Concerning Energy Independence, July 2005,
http://www.cga.ct.gov/2005/ACT/Pa/pdf/2005PA-00001-R00HB-07501SS1-PA.pdf; and Public Act 07-242, An Act Concerning Electricity and Energy Efficiency, June 2007,
http://www.cga.ct.gov/2007/ACT/PA/2007PA-00242-R00HB-07432-PA.htm
51
New Jersey P.L.2011, Chapter 9, Senate, No. 2381, §§1,3,4 - C.48:3-98.2 to 48:3-98.4 §5 C.48:3-60.1, http://www.njleg.state.nj.us/2010/Bills/AL11/9_.PDF; Notice Of Comment Period On Request For Proposals For New Generating Facilities, Maryland Public Service Commission, December 29, 2010,
http://webapp.psc.state.md.us/Intranet/Casenum/NewIndex3_VOpenFile.cfm?ServerFilePath=C:\Casenum\9200-9299\9214\\34.pdf.
52
FCM Calendars and Auction Results, http://www.isone.com/markets/othrmkts_data/fcm/cal_results/index.html
53
Monitoring Analytics conducted analyses of the New Jersey legislation and Maryland PSC
draft RFP showing a reduction in capacity revenues of $3 billion dollars per year ($2 billion
from New Jersey and $1 billion from Maryland).
http://www.monitoringanalytics.com/reports/Reports/2011/NJ_Assembly_3442_Impact_on_PJM_Capacity_Market.pdf; and http://www.monitoringanalytics.com/reports/Reports/2011/IMM_Comments_to_MDPSC_Case_No_9214_20110128.pdf
18
www.PublicPower.org
APPA is most concerned by the
Commission’s holdings in these two
orders, and in particular its seeming
lack of recognition or respect for the
states’ traditional role in assuring
that retail electric service is both
reliable and reasonably priced.
APPA has in the past called for a
respectful dialogue on these issues,
and renews that call here.
order are rule changes that will impose minimum prices on offers from new
natural gas generators. As a result, new natural gas-fired resources procured
by either the state or another LSE, such as a public power utility or a
cooperative, would be likely to have their low-bids replaced with a higher offer
price, making it very difficult for such resources to clear the market. These
rule changes are a significant threat to both LSE self-supply and to statesponsored power procurements. Following the PJM decision, Lee Solomon,
President of the New Jersey Board of Public Utilities, stated that FERC’s order
“does not address the failure of the PJM market to deliver new capacity which
is desperately needed to reduce New Jersey’s energy prices, and to replace
aging, dirty, and inefficient generation facilities.” President Solomon also
stated that the BPU plans to pursue “options available to us that are outside of
FERC’s jurisdiction,” concluding that he does “not believe that New Jersey
forfeited its sovereignty when PJM became the regional transmission
operator.”55
APPA is most concerned by the Commission’s holdings in these two orders,
and in particular its seeming lack of recognition or respect for the states’
traditional role in assuring that retail electric service is both reliable and
reasonably priced. APPA has in the past called for a respectful dialogue on
these issues, and renews that call here.
www.PublicPower.org
54
Order Accepting Proposed Tariff Revisions, Subject To Conditions, And Addressing Related
Complaint, 135 FERC ¶ 61,022 (April 12, 2011),
http://elibrary.ferc.gov/idmws/common/OpenNat.asp?fileID=12617771; and Order On
Paper Hearing And Order On Rehearing, 135 FERC ¶ 61,029 (April 13, 2011), http://elibrary.ferc.gov/idmws/File_list.asp?document_id=13909713
55
News Release, New Jersey Board of Public Utilities, April 13, 2011,
http://www.state.nj.us/bpu/newsroom/news/pdf/20110413a.pdf
19
20
www.PublicPower.org
V.
Bilateral Contracts
O
ne of the core features of APPA’s RTO market redesign proposal is
that LSEs would serve their loads with a combination of owned
generation/demand-side resources and generation/demand-side
resources obtained under longer- term bilateral contracts. Market
participants (wholesale buyers and sellers) could enter into any
contractual arrangement acceptable to both parties, subject to state and
RTO requirements governing the resource portfolio of each LSE and the
eligibility of the seller for market-based rate authority (as discussed
below). APPA is not in this Plan recommending any requirements for LSEs
to enter into bilateral contracts, nor does this plan place any restrictions
on the amount or percentage of power purchased through the
optimization market. Rather, the reforms proposed here are likely to both
incent and remove barriers to bilateral contracting, and reduce potential
for excess earnings in the current market structure.
An important component of the Competitive Market Plan is the phase-out
of existing locational capacity markets. Payments established under
auctions for future delivery years would still be honored for their terms,
but going forward past that time, generation owners and demand response
providers would need to make contractual arrangements to sell their
resources, or sell their resources into the RTO’s optimization market
without the financial backstop of separate capacity market payments.
To support the financing of new power plants, ownership arrangements or
bilateral contracts of at least 10 to 15 years in length would likely be
needed. Such arrangements and contracts would also provide needed
price stability for LSEs and their retail customers. APPA, however, is not in
this proposal specifying minimum or specific contract lengths and terms.
Instead we recommend, and expect, that each LSE would likely develop a
portfolio of diverse resources of varying lengths and terms. The
Competitive Market Plan is intended to improve the overall market
environment by making a significant number of long-term resource
arrangements of 10 years or longer readily available to buyers and sellers.
The RTO’s optimization market would allow for residual optimization of
LSE energy supply arrangements and balancing in real-time.
APPA originally proposed these market structure changes in response to
reports from APPA members and large end-use customers that in RTO
markets, long-term, reasonably-priced bilateral contracts were difficult to
arrange (especially full-requirements contracts).56 Many buyers reported
56
www.PublicPower.org
Communications with APPA members, and testimony summarized in “Executives describe
real-world problems with RTOs,” Public Power Daily, Feb. 29, 2008,
http://publicpower.org/newsletters/ppdailydetail.cfm?ItemNumber=21269&sn.ItemNumber=0 (Login required)
21
that the high prices sellers could obtain in the bid-based RTO-run spot
markets discouraged the signing of long-term contracts, or resulted in
contract offers directly linked to spot market prices.57 Studies of bilateral
markets in RTO regions have shown that such RTO markets pose
impediments to reasonably priced long-term bilateral contracting.58
APPA now believes that there is an additional reason to foster the signing
of at least some longer-term generation contracts that can support the
development of new resources—the need to revamp the nation’s
generation fleet over the coming years to address environmental concerns.
The Environmental Protection Agency (“EPA”) is currently conducting a
series of rulemakings to regulate emissions of greenhouse gases from large
stationary sources, including power plants. In addition, the EPA is in the
middle of a substantial number of other rulemakings, dealing with coal
ash, mercury, and other hazardous air pollutants, criteria pollutants
(smog), water use in once-through cooling systems, and a number of other
items.
As these various rules go into effect, their cumulative effect will likely
make it uneconomic for generators to continue to operate a substantial
number of existing coal-fired power plants. Estimates of coal plant closures
range from 30 to 70 gigawatts (GW) of coal generation within the next ten
years, with most estimates trending towards the higher end of this range.59
A substantial portion of that retiring capacity will have to be replaced,
mostly with natural -gas- fired units. And coal-fired power plants constitute
a very substantial portion of the generation fleets of a number of RTOs.
22
57
For example, Walter Brockway of Alcoa testified before FERC that: “We found no supplier willing to discuss supplying us with anything other than electricity priced to reflect peak load generation, as well as
placing on us all the risk of trans-mission congestion.” Technical Conference to Examine the State of
Competition in Wholesale Power Markets, Docket AD07-7-000, May 8, 2007,
http://www.ferc.gov/EventCalendar/Files/20070508083948-Brockway,%20Alcoa.pdf.
58
E. Hausman, R. Hornby and A. Smith, Bilateral Contracting in RTO Markets, Synapse Energy Economics, April 2008, http://publicpower.org/files/PDFs/EMRISynapseBilateralsReport2008.pdf; also, see the
discussion of fixed-price contracts and supplier behavior in Frank A. Wolak and Shaun D. McRae,
Merger Analysis in Restructured Electricity Supply Industries: The Proposed PSEG and Exelon Merger,
November 2007, ftp://zia.stanford.edu/pub/papers/pseg_exelon_merger.pdf
59
Studies of projected coal plant closures have been undertaken by: The North American Electric Reliability Corporation (10 - 35 GW of coal and 40 - 70 GW of all capacity by 2018), 2010
Special Reliability Scenario Assessment, October, 2010, Table IV-6,
http://www.nerc.com/files/EPA_Scenario_Final.pdf; Credit Suisse Equity Research (60 GW
of coal capacity between 2013 and 2017), Growth From Subtraction: Impact of EPA Rules on
Power Markets, September 23, 2010, http://op.bna.com/env.nsf/id/jstn-8actja/$File/suisse.pdf; The Brattle Group (50 – 66 GW of coal capacity by 2020), Potential Coal Plant Retirements Under Emerging Environmental Regulations, December 8, 2010,
http://www.brattle.com/_documents/UploadLibrary/Upload898.pdf, and FBR Capital (30 –
70 GW in the next few years), EPA regs may shut 70,000 MW of U.S. coal plants: FBR, Reuters,
December 13, 2010 http://www.reuters.com/article/2010/12/13/us-utilities-epa-coal-idUSTRE6BC3JN20101213
www.PublicPower.org
In addition to the financial incentives
for owners of existing merchant
generation to constrain the capacity
supply, many current RTO market
structures simply cannot support
the development of new resources
by newer market entrants.
Unlike generation owned by a vertically- integrated utility, the future
earnings of merchant generation owners would be higher for their
remaining existing plants if a portion of generation is shut down and the
supply of power becomes constrained. One likely scenario is for merchant
generators to strategically close the plants that are the most costly to
retrofit while allowing the remaining plants, especially nuclear and lower
emission coal plants, to benefit from the resulting higher prices.60 Several
recent analyses have found that the closure of coal plants is in fact likely to
be greater for merchant units. The Brattle Group found that most of the
coal plants likely to retire will be merchant units, accounting for 64 to 76
percent of merchant coal capacity compared to 1 to 4 percent of regulated
coal, whose regulated owners would be much more likely to retrofit the
plants.61
APPA therefore believes the industry will need to make substantial
investments in new gas-fired and renewable generation resources as these
coal-fired power plants leave the fleet. In addition to the financial
incentives for owners of existing merchant generation to constrain the
capacity supply, many current RTO market structures simply cannot
support the development of new resources by newer market entrants.
Such generation projects take time to construct, and they generally
require secure financing, anchored by long-term (ten-year or more) power
purchase agreements or other “take-away” commitments.62 This problem
www.PublicPower.org
60
For example, Credit Suisse notes that “the retrofit / closure decision will not occur in a vacuum such that plants ‘on the bubble’ for investment could be attractively economic as other
plants are pulled from the market.” Credit Suisse Equity Research, p. 36. Similarly, Fitch Ratings concluded that: “Merchant generation that does not rely on coal (or coal-fired generation that is already highly controlled) could increase its profitability if a significant portion of
coal-fired generation in the same region is retired and heat rates rise in the region due to
stringent enforcement of new EPA rules.” Time to Retire? US Coal Plants in Environmental
Crosshairs, FitchRatings, February 2011, p. 2 http://www.fitchratings.com/creditdesk/reports/report_frame.cfm?rpt_id=604365
61
The Brattle Group, p. 6
62
In comments submitted by Competitive Power Ventures (CPV) to the Maryland Public Service Commission on RPM, CPV attached several letters from lenders asserting that long-term
contracts are critical for obtaining financing for new generation projects. For example, the
Bank of Tokyo-Mitsubishi wrote that it “favor[s] the projects which operate in markets with
transparent and stable regulatory regimes and projects which benefit from long-term fixedprice power purchase agreements with investment grade counterparties.” Comments of CPV
Maryland, LLC, In the Matter of the Reliability Pricing Model And the 2013/2014 Delivery
Base Year Residual Auction Results, Maryland Public Service Commission, Administrative
Docket PC22, October 1, 2010, Attachment B, http://webapp.psc.state.md.us/Intranet/AdminDocket/NewIndex3_VOpenFile.cfm?ServerFilePath=C%3A%5CAdminDocket%5CPublicConferences%5CPC22%5C35%2Epdf
63
For a detailed discussion of the greater adverse impact on reliability and prices in RTO regions resulting from EPA regulations, see Issue Brief: Why New CO2 Regulations Could Produce Windfall Profits and Unproductive Costs for Consumers, American Public Power
Association, March 2011, http://www.publicpower.org/files/PDFs/IssueBriefWindfallProfitsandEPARegsMarch2011.pdf
23
will be especially pronounced in RTOs with restructured retail markets.63
APPA does not expect that increased reliance on longer-term bilateral
contracts and owned generation will immediately produce lower prices. It
is, however, likely to produce more stable and reasonable prices in the
long run. Shorter-term power supply contracts of three years or less, such
as those procured to provide SOS, frequently include generation prices
above the spot prices set in RTO markets, in part due to the inclusion of
risk premiums.64 Diversified LSE resource portfolios that include longerterm contracts of 10, 20 or more years may still entail some risk premium
because suppliers would be absorbing the risk of reduced demand. But
such premiums are likely to be mitigated by APPA’s proposed price
formation mechanism for the optimization market. This market structure
should better discipline spot prices, which in turn should discipline
bilateral contract prices formed through responses to LSE requests for
proposals, where suppliers of generation and demand response must
compete directly with each other, as well as with the prospect of LSEowned projects. Any risk premiums that suppliers do require are likely to
be exceeded by the benefits of greater price stability.
There is not sufficient data to ascertain the current status of bilateral
contracting in RTO regions. For example, PJM’s State of the Market
reports provide data on the percentage of power purchased through
bilateral contracts, self-supply and spot markets. In the 2010 State of the
Market Report, these data show that 11.8 percent of the power purchased
in the real-time and 4.9 percent in the day-ahead market was sold through
bilateral contracts, a decrease of 1.1 percentage points from the prior year
for the real-time market, and no change in the day-ahead market.65 But
PJM does not break down these data according to the length of the
contract or the pricing terms. Theoretically, a one-week agreement to sell
power at a price indexed directly to prices set in PJM’s spot market would
be counted as a bilateral contract.
24
64
Testimony of Kenneth Rose, Ph.D., Independent Consultant, before the Pennsylvania Public
Utility Commission, November 6, 2008, http://www.puc.state.pa.us/electric/pdf/EnBancWEM/Ttmy-Kenneth_Rose110608.pdf , p. 8 – 11. A presentation by Pennsylvania PUC Chairman James H. Cawley noted that PECO’s default price “includes a risk premium to account
for future load level uncertainty.” Philadelphia Business Journal, 2010 Energy Summit, October 28, 2010, http://www.puc.state.pa.us/electric/pdf/PPT-PBJ_Presentation102810Cawley.pdf
65
2010 State of the Market Report for PJM, Section 2, Monitoring Analytics, March 20, 2011, p.
106-107, http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2010/2010som-pjm-volume2-sec2.pdf. These data are reported at the level of the parent company such
that bilateral sales between generation-owing and load- serving regulated utility affiliates would
be reported as self-supply and not as a bilateral contract. In the State of the Market reports for
2008 and earlier, these data were also reported for the billing company which reported that
about 96 percent of real-time sales were made through bilateral contracts.
www.PublicPower.org
No data on bilateral contracts was found in the ISO New England and the
Midwest ISO State of the Market reports.66 New York ISO reports only on
“physical bilateral contracts,” which involve settlements with the New York
ISO for transmission charges and between the parties privately for the
commodity prices and do not include bilateral contracts that are settled
privately. Physical bilateral contracts comprised about 50 percent of the
day-ahead load in New York City and Long Island, 40 percent in East
upstate, and 60 percent in West upstate in 2008, the last year for which
these data are available.67 As with PJM, there is no information provided
on length or pricing terms.
Moreover, the RTO definition of a bilateral contract does not require that
a contract be tied to associated capacity, such as a specific generating unit.
Some of the bilateral contracts are sales of power to utilities for the
provision of standard offer service load, whose prices are often based on
RTO spot market prices. These SOS contracts need not be tied to specific
generating units, and even if the supplier is delivering electrons from its
own generating assets, prices are still tied to the spot markets, and not the
costs of producing electricity from such units.68
In many other cases, the bilateral contracts used in RTO regions are
standardized and the power product choices do not include capacity
obligations or other provisions that would support new generation
infrastructure. For example, the EEI/NEMA Master Agreement used in
many eastern RTOs contains standardized language for product
definitions, credit requirements and buyer/seller obligations.69 A typical
contract will specify a delivery point, price, quantity and time frame (for
example, “20 MW delivered at [a selected trading hub] during on-peak
hours in calendar year 2008”). These contracts also include “liquidated
damages” or other liability provisions outlining financial responsibility for
www.PublicPower.org
66
An e-mail from ISO New England Customer Services, Dec. 24, 2008, in response to an APPA inquiry about bilateral contracting data states that “we do not report the bilateral contract or spot
market activities.” No response was received from MISO, although the MISO 2009 State of the
Market Report notes that the small portion of capacity clearing the Voluntary Capacity Market
indicates that “most LSEs’ capacity needs [are] satisfied through owned capacity or bilateral
purchases.” (p. 24), http://www.midwestiso.org/publish/Document/55f670_12a43afcc88_7f610a48324a/2009%20State%20of%20the%20Market%20Report.pdf?action=download&_pro
perty=Attachment
67
2008 State of the Market 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 (The
2009 and 2010 State of the Market Reports contain less detail and do not provide separate bilateral load data.)
68
For example, see Letter from Constellation Energy to President Miller and Speaker Busch, May
31, 2006, http://www.sec.gov/Archives/edgar/data/1004440/000110465906038686/a0612885_1ex99d1.html.
69
The provisions of the EEI/NEMA Master Contract are available at http://www.eei.org/industry_issues/legal_and_business_practices/master_contract.
25
failure to perform under the terms of the contract. Under such
agreements, a failure to supply power is not a breach of the agreement,
but merely triggers the obligation on the part of the buyer to “cover” by
obtaining replacement supplies at whatever price the buyer can obtain in
the market at that time, with the seller paying the difference between the
contract and market price. Such contracts may work well for financial
parties interested in trading contracts, but are less than ideal for LSEs
attempting to assemble a portfolio of power supply resources that can in
fact be used to serve load.70 Under APPA’s proposal, a truly vibrant
bilateral market would rely less on standardized contracts developed
primarily for trading purposes, and more on individually negotiated
agreements sufficient to support the development of new generation and
demand-side resources.
In October 2008, FERC required each RTO to dedicate a portion of its
web site for market participants to post offers to buy or sell power on a
long-term basis, concluding “that greater transparency from a bulletin
board for long-term power sales will benefit long-term contracting.”71 A
multiple-RTO bulletin board was set up in response, but appears to have
been of limited use. Periodic visits since February 2010 show no more than
four contract offers posted at a given time. All but one of the contracts
displayed have been just one year in length. On September 21, 2010, only
one contract offer was posted -- for the sale of 2 MW of capacity for a oneyear time frame. No offers were posted on the bulletin board, when it was
again visited on April 15, 2011. It is not clear why this bulletin board has
not been more widely used, but the creation of a more viable market for
bilateral contracting will require much more substantive market reforms
than an on-line bulletin board.
26
70
Many “net buyer” APPA members have found the standard EEI/NEMA contract terms and options unsuitable for their own power procurement needs. APPA therefore developed a package
of modifications to that contract (suitable for use by such buyers), available upon request.
71
Wholesale Competition in Regions with Organized Electric Markets, Order No. 719, 125
FERC ¶ 61,071, 73 Fed. Reg. 64,100 (October 28, 2008), p.165
www.PublicPower.org
VI. Market Power
W
ithout new generation entry or a significant expansion in demand
response and efficiency investments, generators may still have market
power in the long-term bilateral contract markets, just as they now do in
spot and locational capacity markets. This market power cannot be wished
away. Generators are likely to attempt to exercise market power even if APPA’s
Competitive Market Plan is implemented, particularly in the early days of new
market operations. Still, there are a number of reasons to believe that market
power may become less of a problem (at least in the long run) and that
markets would be more competitive under APPA’s Plan:
• In current Day Two RTO markets, suppliers interact with each other
frequently, since the RTO auctions clear on very short time intervals.
This repeated interaction allows generators to observe the strategies of
other bidders and respond in kind, encouraging coordinated bidding
strategies and even tacit collusion.72 A recent study found that the
entities bidding generation units frequently are not the owners, and can
change their contractual control of the units, possibly gaining important
knowledge regarding their competitors’ units.73 Bilateral contracting
processes, especially ones conducted under formal requests for proposals
(RFPs) subject to public scrutiny, such as state-supervised procurements,
would be less likely to be subject to such ongoing coordination.
• Bilateral contracting provides a greater opportunity for customers and
suppliers to negotiate “customized” products to meet the supplier’s and
customer’s particular needs, rather than being force-fit into a
standardized form agreement. Capacity prices arranged through
contracts negotiated under RFP procedures could better reflect the fixed
costs attributable to different resources, whereas centralized capacity
markets pay the same price to all resources regardless of whether they
are a new resource facing a tight financing market, an existing and
largely depreciated facility or a demand response offer with limited upfront investments required. Contract lengths could also be tailored to the
type of resource – shorter-term for energy efficiency measures or longerterm for new capital-intensive generation projects.
• Bilateral contracting affords the customer the ability to select among
different counter-party suppliers based on creditworthiness and other
non-price factors relevant to performance over the long term.
• Compared to transactions in a spot or short-term market, longer-term
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72
Experiments at Carnegie Mellon and Cornell “show that hourly auction markets are ideally
designed to teach participants to manipulate the market to raise profit.” Lester Lave, Jay Apt,
and Seth Blumsack, Deregulation/Restructuring, Where Should We Go from Here? Carnegie
Mellon Electricity Industry Center, 2007, p. 14, http://wpweb2.tepper.cmu.edu/ceic/papers/ceic-07-07.asp
73
John Kwoka, Finnegan Professor of Economics , The Effect of Cross-Control on Bidding Behavior and Prices in Electricity Auction Markets, Northeastern University, September 2010,
http://www.publicpower.org/files/PDFs/kwokacrosscontrol.pdf
27
bilateral arrangements provide revenue stability that makes it possible for
potential suppliers to finance capital-intensive generation projects at
more reasonable capital costs, reducing barriers to entry into the
generation market.74
• Within a day-ahead or hour-ahead time frame, many suppliers have
operational constraints (unit commitment, ramping, etc.) that keep
them from being active bidders in RTO-run spot markets. Since there is
more operational flexibility built into a long-term bilateral contract, a
given buyer could have more potential counterparties.
• Because the Competitive Market Plan would provide the transmission
access and financial rights necessary for LSEs to have more and better
power supply choices, including self-build and ownership of generation if
they receive non-competitive supply offers, LSEs should in the long run
have fewer problems with market power being exercised in the bilateral
market.
To incent participation in bilateral markets, APPA is also proposing that
generators in each RTO region that pass the FERC’s relevant market-based
rate screens should be permitted to sell at market-based rates in bilateral
forward markets. The screens used to determine market power should
include, at a minimum, the existing measures used by FERC and individual
RTO market monitors, such as PJM’s “three pivotal supplier” test. However, to
guard against the exercise of generation market power, APPA believes that
FERC should separately assess market-based rate applicants’ generation
market power in long-term power supply product markets. To the extent that
applicants do not pass such long-term market power screens, their marketbased rate authority would be appropriately conditioned or, if merited,
revoked.
FERC must also ensure that RTO Market Monitors (“MMs”) are truly
independent and have all of the resources necessary to perform their
functions. As APPA recommended in Consumers in Peril, RTO MMs should
have the full cooperation of market participants in data gathering, including
access to company-specific financial information and generating unit cost and
operating data, as well as sufficient resources to carry out their duties. RTO
MMs should also monitor bilateral contract markets, and act on complaints
regarding anticompetitive behavior by sellers or buyers in those markets.
74
28
This is especially relevant in light of the recent economic downturn. A 2009 study commissioned for the Maryland Public Service Commission found that: “The breakdown in the capital markets and recent credit implosion make it more difficult for new merchant resources to
attract financing on competitive terms absent long-term contracts with creditworthy counterparties.” Financial Risk Analysis of the Return to Rate Base Regulation , Levitan & Associates,
Inc. & Kaye Scholer LLP, March 11, 2009, http://webapp.psc.state.md.us/Intranet/sitesearch/Kaye%20Scholer_Supplement%20to%20Final%20Report_Financial%20Risk%20Anal
ysis%20of%20the%20Return%20to%20Rate%20Base%20Regulation.pdf
www.PublicPower.org
Moreover, MM State of the Market reports should provide much clearer and
detailed information on bilateral contracts, indicating the length of such
contracts, whether they are backed by the capacity of specific generating units
or other appropriate arrangements, and whether prices are fixed or indexed
to RTO prices.
APPA, however, remains quite concerned that due to the high concentration
in wholesale power supply markets, exercise of generation market power in
bilateral markets could indeed occur even if APPA’s proposed reforms are
implemented. For this reason, APPA proposes that FERC conduct a review of
regional bilateral wholesale markets three years after implementation of
APPA’s Competitive Market Plan, to investigate whether market power
remains a substantial concern. If the commission finds that market power
exercise is a problem in bilateral markets in RTO regions, appropriate
modifications should be made to FERC’s market-based rate regulations and
RTO market rules to address this problem.
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29
VII. Residual Short-Term and Imbalance Services:
The Optimization Market
B
ecause generator availability and customer demand cannot be
perfectly predicted, and electricity cannot (yet) be stored
economically in sufficiently large quantities, APPA’s proposal includes
an RTO-operated residual “optimization” market. This market would allow
for the co-optimization of offers by generators to sell excess energy and
ancillary services, and for LSEs to obtain economy energy and clear
imbalances. The optimization market also would provides an opportunity for
the sale of variable generation75 not committed under bilateral agreements
and allows for the purchase of replacement power for variable generation not
available at a given time.
APPA believes it is not in the interest of either buyers or sellers to place set
limits on the percentage of load that can be met through the optimization
market. Such limits reduce needed flexibility for LSEs, including their ability
to purchase power from variable generation resources, and restrict the
flexibility of generators (especially variable generators) as well. APPA’s
proposed RTO-run optimization market is designed to minimize the size of
the spot market and encourage bilateral contracting for load not served by
owned resources to the maximum extent possible without unduly restricting
market participant options. Key design features of the optimization market
include:
1) Generator offers to sell into the optimization market would be
limited to no more than their short-run marginal costs (SRMC). The
SRMC includes only those costs that vary with the level of output, primarily
fuels and operations, maintenance and administrative costs that vary with
output. (For example, periodic inspection, replacement and repair of system
components would be included because such maintenance depends upon the
level of output.76) Opportunity costs would not be included in the calculation
of the SRMC77, including for ancillary services, which will be co-optimized
with energy dispatch.
30
75
By “variable generation” APPA means resources that have little control over when they generate due to their dependence on renewable “fuels,” e.g., wind and solar resources.
76
Serkan Bahceci, Julia Frayer, Amr Ibrahim, and Sanela Pecenkovic, A Comparative Analysis of
Actual Locational Marginal Prices in the PJM Market and Estimated Short-Run Marginal
Costs: 2003-2006, London Economics International, Section 5.2, February 2007,
http://www.publicpower.org/files/PDFs/LEIReport2012007.pdf
77
An example of the potential problems arising from the inclusion of opportunity costs can be
seen in PJM’s Regulation Market. Participants in this market must submit cost-based offers,
and if they fail the three pivotal supplier test, their offers are capped at the lower of the pricebased or cost-based offer, plus a margin and opportunity costs. Changes to the margin and
the calculation of opportunity costs increased the cost of Regulation and led PJM’s Market
Monitor to conclude that the results of the Regulation Market were not competitive. 2010
State of the Market Report for PJM, Section 6, Monitoring Analytics, March 20, 2011, p. 448-9,
http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2010/2010-sompjm-volume2-sec6.pdf
www.PublicPower.org
Limited-run resources (e.g., generation units subject to air quality limitations
on run times, and hydro units that must be operated for water use and
recreational purposes as well as power supply production) would be allowed to
include opportunity costs in the event that they are dispatched during a time
when energy prices are lower than they would otherwise earn.
Generators participating in RTO-run markets (whether the generators are
inside the RTO footprint or importing into the RTO region) would be
required to submit auditable SRMC information on the company’s entire
portfolio of generation units to the MM. These data would be available to the
public on RTO Web web sites, as would the offers submitted into the market.
Any differences between supply offer curves submitted to the RTO
optimization market and the cost data held by the MM would need to be
justified by the generator upon request by the MM.78
A potential difficulty with implementation of the SRMC offer cap is that the
generators will have an incentive to inflate their costs. APPA therefore
recommends that FERC develop proxy costs based on available databases or
individual supplier data,79 as well as cost data submitted for units of similar ages
and technologies. Owners of units whose costs exceeded proxy cost data would be
asked to provide additional documentation to the MM explaining the differential.
If this could not be supplied, their offers would be capped at the proxy cost.
Even in the absence of a cost cap on offers into the optimization market, APPA
strongly recommends that all data on offers to sell into wholesale energy markets
be provided to the public on the next operating day, along with operating cost
data submitted to the RTO, with the identities of the generating units unmasked.
This would allow third parties to evaluate market performance and behavior in a
way that only MMs currently can, enhancing transparency.
To facilitate demand response participation in these markets, demand response
offers would not be subject to the cost disclosure requirement; instead they would
submit load-reduction demand curves or minimum price offers above which they
would pledge to curtail a specified amount of load. Demand response offers
clearing the market would receive the LMP less an appropriate offset to reflect
the serving LSE’s cost of providing retail electric service to the reducing customer.80
78
79
80
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The existence of these differences would depend on the frequency with which generators submit
cost data to RTOs. Very short-term swings in fuel prices, for example, might cause actual generator costs to deviate from the cost data held by the RTO. (One possible alternative would be to include some fluctuating fuel-specific index component in generator cost submissions.)
William H. Dunn, Jr., Data Required for Market Oversight, December 2007, p. 7 and footnote
5, http://appanet.cms-plus.com/files/PDFs/dunn2007.pdf
This issue is discussed in great detail in the record of FERC Docket No. RM10-17-000. See, e.g.,
Post-Technical Conference Comments of APPA, filed October 13, 2010, available at
http://www.publicpower.org/files/PDFs/APPAPostTCDRcommentsRM1017101310asfiled.pdf
31
2) LSEs would be required to demonstrate to the RTO that they
possess adequate amounts of generation capacity (either owned or
contracted for) and demand-side resources to meet projected
future needs. This RTO-established resource adequacy requirement for
individual LSEs would prevent them from “leaning” on the optimization
market and avoiding contracts for or investments in generation and demandside resources. It would also prevent the potential exercise of “buyer market
power” (to the extent it might exist, a point which APPA does not concede),
by imposing an obligation on buyers to enter into contract arrangements with
sellers. Close coordination between regional and state-level policies and
between RTOs and the state regulatory authorities in their footprints would
be required to develop these resource requirements. The RTO would be
responsible for determining the overall required level of reserves within its
footprint, while state (or local) authorities would determine acceptable
resource portfolios and other power supply attributes, e.g., contract terms,
fuel mixes, and demand-side/generation ratios for their respective LSEs. The
resource adequacy provisions of the APPA Plan are discussed further in
Section X.
3) A “must offer” requirement into the optimization market would
apply to available resources, including resources not scheduled to
serve loads under LSE ownership arrangements or bilateral
agreements. This requirement would limit opportunities for strategic
withholding behavior. Limited-run resources (e.g., generation units subject to
air quality limitations on run times, and hydro units that must be operated for
water use and recreational purposes as well as power supply production)
would be exempted from the must offer requirement under most
circumstances. Participation of variable resources, of course, would also be
subject to their availability. Owners of generation would be required to submit
a schedule of planned maintenance or refueling outages to the RTO and to
demonstrate compliance with the must offer requirement periodically with
the RTO. Providers of demand-side resources would be required to offer
their resources and products into the optimization market to the extent
required by any contractual or tariff provisions to which they had agreed.
Another critical issue in designing a new RTO optimization market is the
methodology used to establish prices. Current RTO markets use singleclearing-price auctions, where the market-clearing price is paid to all
generators offering a price below the highest accepted offer, irrespective of
their individual offers. To avoid too dramatic a departure from current
market design and in an effort to achieve a compromise, APPA’s proposal
would retain, at least initially, the single-clearing-price structure for use with
the optimization market. Because of past issues with the single-clearing-price
mechanism, however, APPA believes FERC should assess the operation of the
32
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revamped optimization market with this pricing mechanism no later than
three years after the start of the market, with a focus on the restructured states
where most generation is unregulated, to determine whether further market
design changes are necessary to achieve just and reasonable rates, and
therefore benefits to consumers.
The ability to earn short-term profits above SRMC could, at the margin, drive
some lower-cost resources into the RTO’s spot markets.81 Simultaneously, the
single-clearing-price auction would provide short-run and long-run price
incentives for LSEs to develop longer-term portfolios of owned and
contracted-for resources, to reduce reliance on the optimization market.
However, the ability of bidders to engage in behavior intended to increase the
single clearing price well above the marginal cost of even the clearing
resource, (e.g., so-called “hockey stick bidding”), to the mutual benefit of all
resource providers being paid the clearing price, would be greatly reduced by
the SRMC-based offer requirement.
Even more than short-term energy markets, ancillary services markets are
particularly susceptible to the exercise of market power, in part because some
services can be supplied only by a limited number of providers.82 Given the
cost-based offer and must-offer requirements in this proposal, the RTO can
co-optimize supply offers across the energy and ancillary services markets.
Under such a co-optimization, the RTO would simultaneously dispatch energy
and ancillary services centrally,83 paying generators meeting the technical
criteria and selected to supply ancillary services on a cost-reimbursable basis, if
they are not dispatched.
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81
In theory, at the margin the uniform-price auction structure would also provide incentives for
investment in low-cost generation resources. However, this is unlikely to be a significant factor
in APPA’s proposed market redesign, in part because it is expected that this optimization market would be a small portion of overall electricity sales. Investment decisions would be driven
primarily by the resource planning process.
82
See, e.g., 2010 State of the Market Report for PJM, Section 6 at 418 (“The Regulation Market
structure was evaluated as not competitive because the Regulation Market had one or more
pivotal suppliers which failed PJM’s three pivotal supplier (TPS) test in73 percent of the
hours.”) At 426, the report concluded that “Economic withholding remains a problem in the
DASR [Day-Ahead Scheduling Reserve Market].”
83
As recommended by PJM’s MM, operating reserves should continue to be committed on an
hour-ahead basis in combination with a five-minute joint energy market optimization, based
on energy offers. For a more detailed discussion, see Protest and Compliance Proposal of the
Independent Market Monitor for PJM, pp. 51-53.
33
VIII. RTO Operations to Support Non-Discriminatory
Transmission Access
U
nder APPA’s proposal, RTOs would emphasize activities that
support wholesale power supply markets — ensuring
nondiscriminatory transmission access and managing congestion
on the transmission grid, thus ensuring reliability. RTOs would continue
to provide transmission service under open access transmission tariffs
(“OATTs”), dispatch generating units in merit (lowest cost) order
subject to system constraints, manage integration of variable resources,
determine price differentials arising from congestion, and assist LSEs in
hedging congestion. In a market environment focused primarily on
supporting long-term resource arrangements, including both bilateral
contracting and LSE-owned resources, RTOs would need to improve
their management of transmission congestion. As explained in greater
detail in this chapter, they would need to:
• Allocate financial transmission rights (“FTRs”) designed to support
LSE power supply arrangements required to serve load.
• Collect data on bilateral contracts entered into by market participants
transacting within the RTO footprint.
• Centrally dispatch generation in least-cost (merit) order based on
actual costs of generation units submitted to the RTO.
Financial Transmission Rights and Long-Term
Transmission Rights
RTOs would continue to offer OATT transmission service, but would
implement policies to provide greater support to long-term power
supply arrangements. RTOs would allocate annual FTRs or equivalent
rights directly to LSEs based upon a percentage of the LSE’s peak load.
Even where the bulk of energy is transacted through bilateral contracts,
because all contracts would clear through the market, a hedge would
still be needed against congestion costs. LSEs with mid-year changes to
loads or resources should be permitted to apply to the RTO for a
change in their FTR allocations. Any remaining congestion revenues
would be distributed to network and long-term firm transmission
customers to ensure that market participants paying the embedded cost
of the transmission system would receive the full economic value of
their payments or equivalent rights. Non-load-serving market
participants would not be eligible to receive an allocation of FTRs, but
LSEs would retain the right to resell their allocated FTRs if they chose.
RTOs would also allocate LTTRs to LSEs to support bilateral contracts
or owned resources, with a priority for power supply arrangements of 10
years or longer.84 These LTTRs would be paired with LSEs’ power
supply arrangements developed to comply with the RTO’s resource
adequacy requirements, and applicable state resource procurement
requirements. One means to distribute LTTRs would be to provide the
34
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LTTR along with approval of new network transmission service for the
LSE.
However, without adequate transmission infrastructure in place during
the term of the LTTR to support transmission service, the LTTRs might
not provide a sufficient hedge to LSEs against congestion costs. Under
the regulations promulgated in Order No. 2000, an RTO must possess
the authority “for directing or arranging necessary transmission
expansions, additions and upgrades that will enable it to provide
efficient, reliable and non-discriminatory service.”85 FERC decisions
since that order, however, have cast some doubt on this requirement,
and hence on the potential revenue adequacy of LTTRs over their full
term.86 Such financial uncertainties in turn make it more difficult and
costly to develop new generation resources. RTOs should be required to
demonstrate that the data on projected loads and planned resources is
incorporated into transmission system planning and expansion plans, to
ensure that the RTO’s transmission system is sufficiently robust to
support LSE resource portfolios.
The Commission’s currently pending Notice of Proposed Rulemaking in
Docket No. RM10-23-00087 proposes to revise regional transmission
planning and cost allocation protocols and procedures. APPA believes
that if properly done, regional transmission planning could support
allocations of LTTRs to support LSE resource plans. Such resource
plans would inevitably reflect applicable state resource procurement
policies (such as renewable portfolio standards). Therefore,
transmission facilities that are in fact needed to support LSE-selected
generation resources will be necessarily included in RTO’s regional
transmission plans, presuming those plans are based upon the resource
plans of LSEs in the region. Reductions in reliance on transmission
facilities due to increased use of energy efficiency and distributed
generation would likewise be taken into account.
APPA, however, is quite concerned that FERC’s Order No. 741, its final
rule on RTO credit requirements issued on October 21, 2010, in Docket
85
18 C.F.R. § 35.34(k)(7).
86
Midwest Independent Transmission System Operator Inc., 125 FERC ¶ 61,061, P 34 (2008)
(“While we recognize that the Midwest ISO has the obligation to facilitate generation interconnections and expansion planning, it cannot force utilities to build capacity. The Midwest
ISO therefore cannot be required to build sufficient transmission capacity to ensure deliverability of all resources for their useful life.”); Midwest Independent Transmission System Operator Inc., 125 FERC ¶ 61,062, P 162 (2008) (“Also, while the Midwest ISO is obligated to
facilitate generation interconnection and expansion planning, it cannot force utilities to
build capacity and therefore it cannot assure deliverability for all projects’ useful lives.”).
87
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Transmission Planning and Cost Allocation by Transmission Owning and Operating Public
Utilities, 75 Fed. Reg. 37,884 (June 30, 2010).
35
No. RM10-13-000,88 will greatly discourage LSEs from attempting to
obtain LTTRs to support new generation resources, including renewable
resources. The Commission in that order decided to require LSEs
holding FTRs, including LTTRs, to post full financial security to support
all such holdings, despite the acknowledged difficulty in valuing such
holdings for security purposes. Providing such security could well make
it so financially onerous to hold LTTRs that LSEs will be faced with the
decision either to (1) simply accept the risk of transmission congestion
costs associated with such long-term resource transactions; or (2) not
enter into such longer-term transactions in the first instance. Neither
result will assist in assuring the development of the new generation
resources that will undoubtedly be needed in the coming years as
increasing numbers of coal-fired power plants leave RTO generation
fleets.
Collection of Bilateral Contract Data
LSEs would submit their proposed bilateral contracts and owned generation
resource arrangements to the RTO. The RTO would then subject these
contracts and arrangements to a simultaneous feasibility test to determine
whether they violate any transmission system constraints or overload any
system equipment. This information, however, would not affect the dispatch,
which would be done according to actual generator costs and transmission
constraints and would be performed separate from the terms of the
contracts. Bilateral contracts would act as financial arrangements
determining the payment streams between buyers and sellers. The feasibility
test would, however, feed into determinations of FTRs/LTTRs and plans for
transmission expansions and upgrades.
Guidelines for allocating FTRs and LTTRs would need to be established in
the event that all of the power supply arrangements submitted to the RTO
during a particular time window cannot pass the feasibility test. For
example, priority could be given to LSE power supply arrangements with
longer terms, or arrangements that LSEs enter into to meet their service
obligations, as discussed above. The RTO should include such contracts and
arrangements in its regional transmission plan, and ensure that sufficient
transmission facilities are constructed as needed to support them.
Centralized Dispatch
The RTO would centrally dispatch all generation within its footprint,
regardless of whether it is an owned resource, scheduled under a bilateral
contract, or offered to the optimization market. The RTO would use a cost88
36
75 Fed. Reg. 65,942 (October 27, 2010).
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based security-constrained economic dispatch formulation (similar to how
current RTOs operate, except that the RTO would be using actual cost data
of the bidders, rather than submitted bids).89 The terms of the bilateral
contracts would reflect the financial arrangements to be settled between the
buyers and sellers, and would be settled separately from the actual dispatch.
Generators would be paid based on prices negotiated through the bilateral
contracts, or set in the optimization market, as applicable.
89
www.PublicPower.org
Generators would be permitted to designate a zero cost for dispatch purposes if they needed
to dispatch owned resources, to meet contractual obligations or to keep a unit running for
operational reasons.
37
IX. Renewable Energy
A
t least 30 states90 states have implemented renewable portfolio
standards (RPS) or goals under which LSEs are required to provide a
portion of their sales or capacity requirements from renewable or lowemissions generation sources, or from energy efficiency measures. Moreover,
proposals have been made in Congress to enact a national renewable
electricity standard (RES) or clean energy standard (CES). From the point of
view of the RTO, such requirements effectively amount to giving alternative
renewable energy sources some level of priority in the dispatch mix. Some
alternative energy sources, such as biomass or geothermal, can simply
participate in the bilateral market along with traditional fossil and nuclear
generators. Variable renewable generation sources such as wind and solar,
however, can be more difficult to integrate into RTO dispatch mixes, since
there may be a higher risk of unavailability during a particular time interval.
APPA designed its proposed market reform plan to be compatible with such
renewable energy goals and the complications associated with scheduling
variable energy sources. Rather than being set by the “market,” the
penetration level of these variable renewable generation sources will likely be
set based on RPS requirements and other policy considerations determined
by federal, state and local regulators, governors and legislatures.
Operationally, the RTO would simply have to schedule these resources when
they are available (either directly or through individual LSE schedules),
possibly backing down other sources of generation in the process (this
becomes an issue when variable generation resources reach a significant
penetration level within an operating area). In the Day Two markets, which
require a day-ahead commitment of generating units, short-term changes in
output of such variable resources may require the purchase of conventional
power in real-time if the variable resource cannot deliver the day-ahead
commitment in real time, or a reduction in other committed resources if
there is a greater amount delivered.
Since variable resources often are not available at the full contracted amount
in a particular hour, they must be “firmed up” in some manner. One way to
do this would be to require LSEs scheduling wind or solar resources to
develop portfolios of resources that include appropriate backup capacity (e.g.,
natural gas or hydroelectric power).91 But cost of the capacity should be
borne by the variable resource provider as an incentive to schedule as
accurately as they can, as discussed below. These portfolios could be
38
90
Renewable Portfolio Standards and State Mandates by State, U.S. Energy Information Administration, August 2010, based on 2008 data, http://www.eia.doe.gov/cneaf/solar.renewables/page/trends/table28.html
91
This type of arrangement has been explored by C.L. Anderson and J. Cardell , Reducing the
Variability of Wind Power Generation for Participation in Day-Ahead Markets, Proc. of the
41st Hawaii International Conference on System Sciences, Waikoloa, Hawaii, 2008.
www.PublicPower.org
determined by the states in the power supply planning processes described in
Chapters IV and X. Alternatively LSEs would be required to purchase
adequate operating reserves through the ancillary services market to support
their variable resources, with the cost reimbursed by the variable resource
provider. Since this could involve large amounts of operating reserves, the
RTO and state-level regulators would need to cooperatively determine
regional solutions for handling variable resources as part of the resource
adequacy and transmission planning processes.92
One step that could be taken to reduce the amount of capacity or operating reserves
needed is not related to RTO- markets, and simply involves improvements in the
science of forecasting. Obtaining more accurate data and incorporating that data into
scheduling regimes, would be more fruitful than developing entire new market
design features to accommodate variable resources.
In recognition of the difficulty of precisely scheduling variable resources,
APPA has supported the elimination of third-tier imbalance penalties. But
variable resource owners and operators also should have the financial
incentive to schedule as accurately as possible. A combination of carrots and
sticks (e.g., increased opportunities for variable resources to schedule within
the scheduling day and hour, payment by such resources of the associated
capacity and operating reserves, increased access to better forecasting data,
and more coordination by transmission service providers across balancing
areas) should serve to both assist and discipline variable resource providers.
FERC proposed certain measures to promote the integration of variable
resources in a proposed rule issued in November, 201093 that would require
transmission providers to offer all customers the option to schedule
transmission service at 15-minute intervals instead of the current hourly
scheduling norm, and to offer regulation service to generators located within
a transmission provider’s balancing authority area.94 The proposed rule also
would amend the standard interconnection agreement for large generators to
require variable generators to provide meteorological and operational data to
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92
In its comments filed on the Commission’s Notice of Inquiry in Integration of Variable Energy
Resources, FERC Docket No. RM10-11-000, on April 12, 2010, APPA commented at length on
possible measures FERC could require transmission providers to take to better integrate variable
energy resources into regional transmission systems. APPA’s comments are available at
http://www.publicpower.org/files/PDFs/APPARM1011Comments41210asfiled.pdf
93
Integration of Variable Energy Resources, Notice of Proposed Rulemaking, 133 FERC ¶
61,149, (November 18, 2010), 75 Fed Reg. 75,336 (December 2, 2010)
94
The proposed rule would add a new rate schedule for this mandatory service, including a
mechanism through which transmission providers can recover the costs. A transmission
provider could not require a variable generator to purchase greater volumes of generator regulation service than conventional generators unless the transmission provider offers 15minute scheduling and power production forecasting, and can demonstrate that any
requirement that variable generators purchase more regulation service is commensurate with
their proportionate effect on net system variability.
39
The increased reliance on longer
termlonger-term PPAs in the APPA
plan may therefore better support
new renewable resource
development than the current shortterm RTO market model.
transmission providers, and "encourage" transmission providers to develop
power production forecasting for variable generators.
As additional amounts of variable resources are integrated into the grid, there
will be a greater need for capacity and operating reserves as backup power.
This additional resource need reinforces the importance of market reforms to
avoid expenditure of additional and unnecessary costs. For example, recent
increases in locational capacity prices in PJM would make wind power
integration more expensive as additional capacity to back up the wind power
has to be purchased at these higher prices. In the event that scarcity pricing is
implemented, tapping into operating reserves could trigger the increases in
the price ceiling and similarly create additional costs for consumers.
Reforming capacity markets and limiting the use of scarcity pricing would
therefore make integration of renewable resources more affordable.
APPA also notes that distributed (local) generation, energy storage and micro-grids
are emerging alternative energy sources that may not be included in current RPS
regimes but may benefit consumers more when compared to the price of purchasing
energy from the grid. During times of peak or rapidly fluctuating demand, local
generation or energy storage may also impart significant benefits to the grid as a
whole, relieving strain on transmission and generation facilities. The RTO would need
to develop tariff provisions accommodating LSE use of these distributed generation
sources as a way to meet resource adequacy requirements.
An assertion that has been made repeatedly in the ongoing debate over restructured
markets is that RTO-operated markets are more advantageous for renewable power.95
As stated earlier, because this Plan leaves intact the beneficial functions of RTOs, such
as the ability to dispatch a wide array of resources and elimination of pancaked
transmission rates, these advantages of RTOs for renewable power would not change.
Finally, RTO operations are secondary to the importance of providing longterm revenue stability for investors in renewable energy through long-term
contracts. The importance of long-term contracts for renewable power is
demonstrated by a Department of Energy (DOE) finding that in 2009, 58
percent of new wind capacity was purchased by investor-owned or public
power utilities under long-term contracts.96 Regarding the 38% of wind sold
as merchant power into the wholesale markets, the DOE concludes “that it is
40
95
For example, see Joint Statement Supporting Competitive Wholesale Electricity Markets,
American Wind Energy Association and the COMPETE Coalition, October 2010,
http://www.competecoalition.com/resources/compete-awea-joint-statement-supporting-competitive-wholesale-electricity-markets
96
2009 Wind Technologies market Report, Office of Energy Efficiency and Renewable Energy,
US Department of Energy, August 2010,
http://www1.eere.energy.gov/windandhydro/pdfs/2009_wind_technologies_market_report.pdf,
www.PublicPower.org
possible that many projects that sold power on a merchant basis in 2009 may
now be seeking longer-term PPAs in order to gain increased revenue stability.”
In fact, it has become increasingly apparent, that, without a long-term
contract, financing renewables is nearly impossible in many cases. An article
on renewable energy projects in The International Business Times states:
“Now, projects without strong institutional backing and a signed, long-term
PPA won't even make it to bank credit committees.” The increased reliance
on longer-term PPAs in the APPA plan may therefore better support new
renewable resource development than the current short-term RTO market
model.
97
www.PublicPower.org
The Week in Green Energy: The Bankable Project, International Business Times, November
21, 2010; http://uk.ibtimes.com/articles/20101121/week-green-energy-bankable-project.htm
41
X. Resource Adequacy and Planning
A
PPA’s Competitive Market Plan does not include any explicit RTOadministered payments or markets for generation capacity. Studies of
the PJM and NY ISO capacity markets reveal that these markets have
generated payments to generators far in excess of what would be needed to
cover the actual costs of new capacity needed for reliability.98 A recent analysis
shows that high prices within the constrained zones in PJM’s Reliability
Pricing Model have not incented greater levels of new generation clearing the
RPM auctions or higher offers of existing plant upgrades, demand response,
energy efficiency resources, and net imports in constrained zones.99
Given these flaws in the RTO-operated capacity markets, APPA believes it
would be far better to use a combination of resource adequacy requirements,
a comprehensive transmission planning process, and long-term bilateral
power supply and demand response arrangements to ensure adequate supply
resources in RTO regions in future years. If desired by the stakeholders in a
particular RTO region, a voluntary residual capacity market could also be
included in the array of options for those LSEs finding themselves short of
capacity in the nearer term.
Overall RTO-established resource adequacy standards applicable to all LSEs
are an important feature of the APPA proposal.100 These standards may have
to be tailored by the RTO for specific subregions within its footprint,
depending on transmission constraints and other factors. APPA is aware that
there are jurisdictional disputes over the exact level and nature of RTO-set
resource adequacy requirements. Generation adequacy requirements
traditionally have been the purview of state utility regulators and reliability
entities. An increased RTO/federal role would require coordination and
cooperation among state regulators, RTOs, and FERC in establishing and
approving regional resource adequacy plans. This section lays out in more
detail the resource adequacy provisions of the Competitive Market Plan.
Appendix A of this paper provides a background discussion on the current
resource adequacy provisions in restructured markets.
APPA’s proposal would establish a multi-state regional process to develop
needed RTO-wide resource adequacy requirements under agreed-upon policy
goals. States would then implement procurement processes to ensure that
state-regulated IOU LSEs obtain a diversified portfolio of power supply and
demand-side resources of varying lengths and terms that will assist in meeting
42
98
See Mount (2007) and Wilson (2008).
99
Direct Testimony of James F. Wilson in Support of First Brief of the Joint Filing Supporters,
Federal Energy Regulatory Commission, Docket ER10-787, July 1, 2010, Section V,
http://www.wilsonenec.com/FCM_Testimony_July_1.php
100
These standards would be applied to a number of years going forward, with the precise time
frame to be determined.
www.PublicPower.org
the RTO-wide resource adequacy requirements.101 States and LSEs could also
agree to pool their LSEs’ respective resource needs for procurement
purposes, rather than having each individual state or LSE act on its own. Such
procurement processes would greatly benefit new suppliers of generation,
demand response and energy efficiency technologies by providing revenue
streams needed to support long-term financing. Sufficient safeguards also
need to be included in the selection process to ensure that third-party
suppliers get fair and equitable consideration of their offers and proposed
projects.102
Demand response resources should be fully considered in developing LSE
resource portfolios. But caution should be exercised to avoid overreliance on
demand response resources, which have accounted for an increasingly
substantial percentage of the reliability requirements in recent years.103 In the
2010 auction in ISO-NE’s Forward Capacity Market, 8.7 percent of the
capacity procured was demand response.104 In PJM, demand response was
6.3% of peak load in the 2010/2011 delivery year, approaching PJM’s prior
7.5% limit for the limited demand response product.105
101
Public power and cooperative utilities in RTO regions, because they have retained their obligation to serve retail customers, already develop and implement such resource adequacy
plans, under the supervision of their local governing bodies. They conduct periodic generation procurements, assessing “buy v. build” generation options, as well as the use of demand
response and energy efficiency measures to reduce demand, in lieu of securing additional
generation. Because they are not-for-profit and do not earn a return on owned generation assets as investor-owned utilities do, they approach these decisions from a consumer-benefit perspective. For these reasons, public power utilities should continue to procure their resources
under their own plans, unless they choose to opt into a larger state procurement process.
102
State competitive procurement “best practices” are discussed at length in a 2008 paper prepared for the Collaborative on Competitive Procurements between FERC and the National
Association of Regulatory Utility Commissioners (NARUC). Susan Tierney and Todd
Schatzki, Competitive Procurement of Retail Electricity Supply: Recent Trends in State Policies and Utility Practices, July 2008, http://www.naruc.org/Publications/NARUC%20Competitive%20Procurement%20Final.pdf
103
The North American Electric Reliability Corporation (NERC) listed the “Uncertainty of Sustained Participation in Demand Response Programs” as one of the Emerging Reliability Issues
in 2010, stating that: “While many similarities exist between Demand Response and generating capacity, key differences in terms of availability, performance, and sustainability may appear as a given system becomes more stressed… Demand Response is increasingly being used
to balance system load and relieve resource adequacy and transmission reliability issues. Decreased or insufficient participation could lead to operational challenges where peak demand
is not able to be met by current generation or transmission resources.” 2010 Long Term Reliability Assessment, p. 59.
104
Final Capacity Auction Results: Surplus Resources Available for 2013–2014, ISO-New England, http://www.iso-ne.com/nwsiss/pr/2010/fca4_filing_release.pdf. The table on p. 3
shows that 37,501 MW of capacity was acquired, of which 3, 261 MW was demand resources.
105
www.PublicPower.org
Demand Resource Saturation Analysis, Resource Adequacy Planning Department, PJM, May 2010,
http://www.pjm.com/~/media/committees-groups/committees/oc/20100817/20100817-item03-demand-response-saturation-report.ashx. PJM has recommended increasing the limit to 8.5%
for the RTO, finding that this level would produce a low probability (10%) of a resource being interrupted more than 10 times
43
Given these high levels, the risks of future potential non-performance of
demand response resources need to be assessed. Were large amounts of
demand response not to materialize when called upon, the result would be an
adverse impact on system operations comparable to the sudden loss of a large
amount of variable generation. APPA accordingly supports the right of the
RTO to impose technical requirements and verification criteria on demand
response resources to ensure that these resources do perform as intended, if
they are to be counted in an LSE’s resource portfolio. Such requirements and
criteria, however, must be well supported to avoid discriminating against
demand response and in favor of other resources.
Energy efficiency investments as an alternative to generation resource
obligations must also be fully considered. Given that utility LSEs already
provide retail service to end-use customers, the LSE may be the lowest-cost
supplier of demand response or efficiency services. But as part of the regional
procurement process, third-party demand response providers could bid to
provide such services to LSEs. Because demand-side resources may in fact be
the lowest-price supply options (in addition to being the lowest carbonemitting options), they should be an important part of the resource portfolio
for the region and for LSEs.
State requirements and policy preferences for fuel diversity (such as state RPS
and energy efficiency goals, and state/regional carbon mitigation regimes)
should be honored in developing LSE resource portfolios. The RTO would
have to ensure, however, that the LSE resource portfolios developed are,
taken as a whole, both technically feasible and operationally reliable.106 (For
example, an LSE’s 50 percent wind portfolio might exceed an applicable state
RPS requirement, but it would not necessarily be adequate or reliable from
the RTO’s standpoint unless sufficient backup supply/storage were available.)
Another important issue in constructing competitive procurements for stateregulated LSEs is to determine who will conduct the solicitation for bids and
evaluate the submitted bids. The details of current programs vary from state
to state, but in general, current state auctions or bidding programs to
determine which suppliers will supply retail customers are either conducted
by the state commission directly (for example, Maine or New Jersey) or by the
regulated utility (that is, the LSE) under the supervision and oversight of its
state commission (for example, Delaware, Maryland, or Massachusetts).107 An
44
106
One issue that may arise is whether to allow “liquidated damages” contracts to be included in
an LSE’s resource portfolio, and to count towards meeting the RTO’s resource adequacy requirement. Although not directly linked to a specific generating unit, such contracts should
be allowed at least for a transitional period, so that LSEs may continue to use existing agreements in their portfolios to meet the relevant standards in the short run, and transition to
qualifying power supply arrangements.
107
If the regulated utility is to take the lead, this should be done under the close supervision of
the relevant state commission.
www.PublicPower.org
independent third party designated by the state or LSE (with state approval)
could also administer the procurement process.
Once the selection of the resources is determined, contractual arrangements
with the suppliers or providers of the resources (including arrangements for
selected self-build options) would be made. The objective would be for LSEs
to have a diversified portfolio of resources, including longer-term supply
commitments that provide customers electricity at a relatively stable and
reasonable price, while assuring suppliers a steady revenue stream that can
support financing of new resources. APPA’s intention here is to recapture the
benefits to consumers of the long-term commitments and obligations that
regulated utilities had under traditional cost-based regulation to provide
reliable electricity at a just and reasonable price, while at the same time taking
full advantage of available wholesale competitive options to discipline prices
and suppliers. As previously discussed, these longer-term contracts would be
balanced by a portfolio of medium- and short- term contracts.
APPA’s plan has the following advantages over the current system:
• The planning and procurement process can provide a means for meeting
individual state policy goals in a regional process (such as renewable
portfolio standards or demand management programs).
• Progress can be monitored as the process moves through the planning
and procurement stages and any necessary adjustments can be made
along the way. Accountability for LSE resource adequacy is left primarily
to the states and LSEs.
• This method allows the resource planning and procurement process to
be conducted by the parties involved (LSEs and states), after the RTOwide determination is made on overall resource adequacy requirements.
• The use of competitive procurement processes, including self-build
options, to make the actual resource selections allows for competitive
forces to provide price discipline on wholesale resource decisions.
• Increased reliance on longer-term supply commitments should reduce
the supply adequacy problems caused by overreliance on short-term
RTO-run energy markets and the overpayments for existing capacity
produced by some RTO-run locational capacity markets.
www.PublicPower.org
45
46
www.PublicPower.org
XI. Transmission Planning
A
parallel effort to create a more integrated transmission planning,
siting and construction process would also be necessary to implement
APPA’s proposed market reforms. A critical and yet to be resolved issue
is transmission congestion that remains in key pockets of regional
transmission systems. Relying on the transmission owner members of RTOs
themselves to build transmission facilities in response to congestion-based
“pricing signals” in Day Two RTOs generally has not worked well. The
Commission’s pending notice of proposed rulemaking on transmission
planning and cost allocation is clearly intended to improve transmission
planning processes. APPA believes that RTO transmission planning and cost
allocation processes could be greatly improved by more specifically
incorporating LSE resource plans, and that such incorporation is in fact
required under Section 217(b)(4) of the Federal Power Act.108
Current RTO transmission planning processes lack a clear linkage between
LSEs’ long-term resource commitments and long-term transmission
availability (in the form of viable LTTRs that would fully hedge associated
transmission congestion costs). As discussed earlier, not only does the
Competitive Market Plan recommend that LSEs with long-term power supply
arrangements be given priority in allocating LTTRs/FTRs, but also that LSEs’
long-term resource portfolio choices feed directly into RTO transmission
planning. Priority should be given to transmission infrastructure needed to
support such resource arrangements.
RTO transmission planning processes require cooperation among the RTO’s
transmission owners to construct the transmission facilities needed to serve
the present and future needs of the entire region. Incentives to do so,
however, are muddied by thorny cost allocation issues, the prospect of tough
siting battles and generation/transmission cross-ownership.
A related problem is that of transmission constraints that affect resource
decisions. For example, if an LSE wishes to contract for long-term power
supplies from a generation unit at a specific location in the RTO’s footprint,
but there are transmission constraints between the proposed resource and the
LSE’s load, how should this be handled? Ultimately, the RTO would need
legal support from state authorities and FERC to require member
transmission owners to construct sufficient transmission upgrades to support
LSEs’ long-term power supply choices, as incorporated into their resource
portfolios.
Even when transmission owners in RTO regions have undertaken substantial
108
www.PublicPower.org
For a fuller discussion of APPA’s views on the Commission’s pending NOPR on transmission
planning and cost allocation, see the initial comments APPA filed on September 29, 2010, in
Docket RM10-23-000, available at
http://www.publicpower.org/files/PDFs/APPARM1023Comments92910asfiled.pdf
47
new transmission projects, they have insisted on (and generally obtained from
FERC) very generous transmission rate incentives that unduly increase retail
electric rates to consumers. The granting of transmission rate incentives,
rather than being reserved for those cases in which incentives are truly
needed to move a transmission project forward, are now often being granted
by the Commission routinely. Moreover, the packages of incentives granted,
taken together, can go far beyond what is required to reduce the risk of a
transmission project to reasonable levels. While it is indisputable that
additional transmission infrastructure is needed, the Commission’s failure to
keep the costs of that additional infrastructure within reasonable bounds is
contributing to growing opposition to the allocation of the resulting costs of
such projects.
APPA therefore supports the Commission’s issuance of its May 2011 Notice of
Inquiry109 seeking comments on its transmission rate incentive policy first set
out in Order No. 679.110 APPA believes that transmission rate incentives
should be granted only to extraordinary transmission projects that are found
to be needed and that would not be constructed but for the granting of such
incentives. Moreover, the incentives should be limited to a reasonable
package of measures that, taken together, reduce the risk of the project to
acceptable levels for both project applicants and end- use consumers, without
resulting in unjust and unreasonable rates.
111
109
Promoting Transmission Investment through Pricing Reform, Notice of Inquiry, 135 FERC 61,
146 (May 19, 2011)
110
Promoting Transmission Investment Through Pricing Reform, Order No. 679, FERC Stats. &
Regs. ¶ 31,222 (2006), order on reh’g, Order No. 679-A, FERC Stats. & Regs. ¶ 31,236, and
order on reh’g, 119 FERC ¶ 61,062 (2007). APPA welcomes recent indications from the Commission that it recognizes the need for such a review. For example, FERC Commissioner John
Norris voiced concerns similar to those of APPA in his 2010 concurrence to an order approving certain incentives for a transmission project in the PJM region:
“…[T]he Commission’s current approach may not appropriately balance the different types of
incentives awarded to a project. Some incentives, such as the collection of rates during construction work in progress (CWIP) and the approved recovery of prudently incurred costs if
the project is abandoned, serve to substantially lower risk for investors in the project. Other
kinds of incentives, such as an incentive ROE adder, give investors the opportunity for greater
rewards. The Commission has not articulated a sufficiently clear framework to balance requests for packages of incentives that individually seek to both limit downside risk and provide greater potential upside rewards.” [Emphasis supplied.]
Potomac Appalachian Transmission Highline, L.L.C., 133 FERC ¶ 61,152 at 61,737 (2010)
(PATH)
111
48
For a more detailed discussion of the transmission rate incentives issue, see the Joint Comments of the
American Chemistry Council, et al., Docket RM10-23-000, Federal Energy Regulatory Commission, September 29, 2010, http://www.publicpower.org/files/PDFs/JointCommentsRM102320100929.pdf
www.PublicPower.org
XII.
Transition Issues
I
t has now been over a decade since the Federal Energy Regulatory
Commission issued Order No. 2000. The course of RTO market
development since that time has been difficult and controversial. The
transition period to implement needed RTO market reforms is also likely to
be prolonged and contentious, with bumps in the road and the possible need
for mid-course corrections.
For market participants that have made investments and resource
procurement decisions under existing market structures that would be
undergoing changes, implementation of the APPA Plan would likely require
mechanisms to avoid or at least minimize economic injury during a
substantial transition phase. For example, owners of capacity and demand
response providers receiving payments under an RTO-run locational capacity
market may require an orderly phasing out of such payments over the
remaining term of the RTO’s forward market auction windows, even as
resource adequacy requirements for LSEs are phased in.
APPA’s proposed market redesign, which couples bilateral contracts and
resource ownership with centralized dispatch, is compatible with FTRs, as are
current RTO markets. Because this plan would not reinstitute physical
transmission rights, the transition would be less difficult. The transition might,
however, still impact the FTR holdings of some market participants. Since
real-time dispatch would be based on costs rather than on market-based
offers, the pattern of power flows in the transmission network would change
to the extent that past market-based supply offers have been different than
costs.
Many aspects of the APPA Plan, such as the requirement for submission of
short-run marginal costs for dispatch and optimization markets, may require
FERC proceedings to work out the details, and likely would prove
contentious. The recommendations for state-supervised procurement
processes for state-regulated LSEs will likely entail state-level regulatory
changes, or even new legislation. But even before the completion of the
transition, steps taken to implement the Plan’s features could have near-term
positive impacts on financing availability, by increasing the confidence in
electricity markets on the part of lenders and investors. Moreover, reform of
the RTOs’ short-term markets alone might have a salutary effect on the
bilateral markets, providing an incentive for generators to offer more
customized and attractive products and to bargain in a more meaningful
fashion with prospective buyers.
www.PublicPower.org
49
XII.
Conclusion
I
mplementation of the Competitive Market Plan would take a
substantial period of time. Many thorny transition issues would have to
be resolved. There are substantial institutional and political obstacles as
well. Differences in market design details among RTOs and differences in
state retail regulatory regimes would require customized application of APPA’s
Plan in each RTO. Hence, APPA suggests its Plan as one path to reach
necessary long-term goals for the electric utility industry, including the
development of new financial arrangements necessary to support new
resource development in the wake of the 2008 financial crisis and subsequent
deep recession, and in anticipation of a coming wave of coal generation unit
retirements triggered by EPA regulatory actions
Above all, APPA intended by proposing its Plan in 2009 to start a rational
debate about the future of RTO markets—a debate the industry now more
than ever needs more than ever to have. RTO-run centralized power supply
markets are not working as originally envisioned. The resulting dysfunction
has had substantial negative implications for the economy, reliability and the
cost of retail electric service in RTO regions. The industry needs to start
talking about necessary reforms. Before this dialogue can commence,
however, those who advocate “competition” in wholesale electric markets have
to acknowledge the current substantial problems with RTO-run centralized
power markets. The debate should no longer be about whowhom can best
massage the statistics or whether it is more virtuous to support “competition”
or “regulation.” Instead, the industry must work together to develop a
regulatory regime for electricity markets in RTO regions that will truly benefit
consumers, businesses and the environment. Unless the electric utility
industry and all of its regulators, retail and wholesale, can agree on a market
design and regulatory paradigm that fairly balances the interests of both load
and generation, the industry will be condemned to continued upheaval.
50
www.PublicPower.org
APPENDIX A
Division of Responsibilities for Resource Adequacy
in Current RTO Market Structures
The current RTO market structure has not provided for a robust set of
resources to meet future projected demand at reasonable costs, nor has it
produced sufficient diversity of fuel supply or low-carbon energy
development. In short, sole reliance on “market” forces to determine resource
amounts and fuel mixes is not likely to achieve such goals. Long-term
planning and better-supervised resource procurement is therefore needed for
resource adequacy of supply and demand resources and transmission.
Achievement of such goals is critical to the RTO’s ability to support longerterm power supply arrangements, operate short-term energy markets, provide
transmission service and ancillary services, and carry out other RTO functions.
This section outlines the shortfalls in the current resource adequacy
procedures and provides additional background to the Resource Adequacy
provisions in Section X of the Competitive Market Plan.
Resource adequacy under cost-based regulation
Under a cost-of-service based regulatory framework, states and utilities
developed and used procedures for decades to ensure that sufficient
resources were available to meet projected customer demand. As the
regulatory system evolved over time, utilities had the responsibility to plan and
maintain the system to reliably meet customer demand.112 Since utilities were
generally the sole providers of electricity to customers (and were usually
granted exclusive franchises to operate in their service territory), they were
regulated and provided sufficient funds to operate, maintain and expand
their systems, and to earn a return on their investment. States generally had
the authority to regulate retail rates of their jurisdictional utilities, and
approved prudent costs for new generation that was deemed used and useful
for customers.
Table 1 summarizes resource acquisition under cost-based vertically integrated
regulation. Utilities generally took the responsibility and did the planning to
acquire new resources, and had both the incentive and the obligation to do
so. FERC’s authority was limited to regulation of “sales for resale” (wholesale
sales) and wholesale transmission service—having only limited impact on the
resource choices of vertically integrated utilities (except for the siting of
hydroelectric generation facilities). In general, this arrangement worked well
enough to build a great deal of the infrastructure we still use today. It was not
112
52
Many states still use this form of cost-of-service or “traditional” regulation, and likely will continue to use it for the foreseeable future. However, some states in RTO areas, and particularly
states with retail access, have either modified how utilities or other LSEs acquire new resources or have shifted responsibility for new resources shifted from primarily utilities to the
region or RTO markets.
www.PublicPower.org
perfect, of course. Utilities were sometimes provided incentives to overcapitalize or over-build their systems.113 To offset that incentive, states
developed the prudent investment and used- and- useful tests. Application of
these tests added to the administrative costs and may have caused some
reluctance on the part of state-regulated utilities to add capacity. However,
from an overall pragmatic standpoint, this system supported the construction
and maintenance of a reliable and affordable system, much of which we still
rely on to this day.114
Table 1.
Resource adequacy under cost-based regulation.
Load- Serving RTO
Entities (utilities)
Responsibility
FERC
States
X
Authority
X
Incentive
X
Planning
X
Resource adequacy with an RTO structure
Under the current RTO system, responsibility, authority, and planning have
become more fragmented among federal, state and non-governmental RTO
authorities. RTOs plan for the needed resources for the system (on a systemwide basis), but they do not build anything themselves and have been highly
reluctant to force anyone else to do so. States authorize projects within their
jurisdiction, approving siting of generation and transmission facilities. FERC,
even with its expanded role under restructuring,115 can only provide
“incentives,” but does not order (or has not yet tried to order) specific
generation or transmission projects. Neither FERC nor the states usually
become directly involved in constructing projects. Generators, left to their
own choice, will choose technologies and fuels that make the most economic
sense from their standpoint and investment time frame, which does not
necessarily match the needs of the overall regional system. A generation
www.PublicPower.org
113
This includes the Averch-Johnson effect, also called “goldplating,” and “ratebase padding.”=
114
Perhaps one of the most famous failures of this system, one that helped usher in industry restructuring, was the nuclear power plant cost overruns of the 1970s and 1980s. However, it
could be argued that this was simply the result of poor regulation, not a failure of the system
itself.
115
As wholesale and retail restructuring has developed since the late 1980s, the amount of electricity that passes through some type of FERC-regulated control has increased. This has occurred as a result of both federal and some state legislation and regulatory changes, such as
divestiture of IOU generation.
53
resource mix with an overreliance on one fuel may be inadequate for
reliability purposes.
As can be seen in Table 2, under an RTO system, responsibility, authority,
incentive, and planning are divided among LSEs, RTOs, FERC, and states.
The misalignment of responsibility with incentive and planning, in particular,
creates a challenge that has been addressed in cumbersome and costly ways.
For example, RTOs have created forward capacity markets to provide
incentives to provide new generation capacity and demand response. The
incentive to build has shifted from utilities to IPPs and others willing to take
on the financial risk. However, these generators have no responsibility to
maintain system reliability, no obligation to customers beyond their specific
contract arrangements, and no system planning requirements.
Table 2.
Resource adequacy within RTO footprint.
Load- Serving
Entities (utilities)
Responsibility
RTO
Planning
States
*
X
X
Authority
Incentive
FERC
**
X
* Very limited backstop transmission siting authority for projects sited in “national interest transmission
corridors,” as designated by DOE, and siting authority for hydroelectric facilities.
** Only for remaining vertically integrated utilities with supply obligation to retail customers.
A similar misalignment has occurred with transmission planning and
expansion. Under cost-based regulation, responsibility for grid reliability was
clearly with the utility. If there were any interruptions of service, the utility was
directly responsible. But this responsibility has now been shifted to RTOs.
RTOs do the planning, but they do not build any transmission facilities and
generally have not required their member transmission owners to do so.
FERC can authorize recovery of transmission project costs if an entity
proposes to build new transmission or expand its existing transmission system
(including rate incentives), but has not tried to order such entities to do so.
States approve the siting of new transmission lines and (in many cases)
approve significant expansion of existing lines, but only rarely have required a
transmission owner to expand its system. Moreover, the incentive for
transmission owners that also own generation is often to not expand their
facilities because it will lower prices for their generation.
54
www.PublicPower.org
American
Public Power
Association
1875 Connecticut Avenue, NW
202.467.2900
Suite 1200
www.PublicPower.org
Washington, DC 20009-5715

Competitive Market Plan - American Public Power Association

Transcription

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