[Federal Register Volume 65, Number 217 (Wednesday, November 8, 2000)]
[Notices]
[Pages 67040-67065]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-28447]



[[Page 67039]]

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Part II





Department of Energy





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Federal Energy Regulatory Commission



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Order Proposing Remedies for California Wholesale Electric Markets and 
Order Specifying Time of Conference and Procedure for Seeking 
Participation; Notices

  Federal Register / Vol. 65 , No. 217 / Wednesday, November 8, 2000 / 
Notices  

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

Docket Nos. EL00-95-000, EL00-98-000, EL00-107-000, ER00-3461-000, 
ER00-3673-000]


San Diego Gas & Electric Company, Complainant, v. Sellers of 
Energy and Ancillary Services Into Markets Operated by the California 
Independent System Operator and the California Power Exchange, 
Respondents; Investigation of Practices of the California Independent 
System Operator and the California Power Exchange; Public Meeting in 
San Diego, California; California Power Exchange Corporation; 
California Independent System Operator Corporation; Order Proposing 
Remedies for California Wholesale Electric Markets

Issued November 1, 2000.

Table of Contents

Introduction and Summary
Background
    A. California Restructuring
    B. Events of Summer 2000
    C. Commission Actions in Response
    D. Docket No. ER00-3461-000
    E. Docket No. ER00-3673-000
Interventions and Other Pleadings
Procedural Matters
Discussion
    A. Overview
    B. Proposed Immediate Measures
    1. Requirement to Sell Into and Buy From the PX
    2. Underscheduling of Load and Resources
    3. Governance of the PX and ISO
    4. Interconnection Procedures
    C. Longer-Term Measures
    1. Reserve Requirement
    2. Alternative Auction Mechanisms
    3. Balanced Schedules
    4. Enhanced Market Mitigation
    5. Congestion Management Redesign
    6. Demand Response Program
    7. Importance of RTO Development and Compliance
    D. Price Mitigation and Refunds
    1. Price Mitigation Measures
    2. Refund Liability of Public Utility Sellers in the ISO and PX 
Markets
    E. Docket Nos. ER00-3461-000 and ER00-3673-000
    F. Actions Others Should Take
    1. Offering a Full Menu of Forward Products
    2. Additions of Generation and Transmission Capacity
    3. Demand Response
    4. Elimination of Impediments to Forward Contracting
Hearing Based on Written Submissions and Oral Presentations to the 
Commission

Introduction and Summary

    On August 23, 2000, the Commission issued an order in Docket Nos. 
EL00-95-000 and EL00-98-000, initiating hearing proceedings under 
section 206 of the Federal Power Act (FPA) to address matters affecting 
bulk power markets and wholesale energy prices in California.\1\ The 
Commission held the hearing in abeyance, however, pending the results 
of a separate staff fact-finding investigation, ordered by the 
Commission on July 26, 2000, of the conditions in electric bulk power 
markets (including volatile price fluctuations) in various regions of 
the country.\2\ The Commission has now had the opportunity to analyze 
the staff investigation report (Staff Report) as it pertains to 
California and the Western region, and has placed that report in the 
record of this proceeding. Based on that report, as well as other 
submissions in these dockets \3\ and the Commission's experience in 
dealing with evolving California market issues in over 85 Commission 
orders since the time the restructured California markets began 
operation in 1998, and based on the seriousness of market dysfunctions 
and recent pricing abnormalities in California, in this order the 
Commission is proposing specific remedies to address dysfunctions in 
California's wholesale bulk power markets and to ensure just and 
reasonable wholesale power rates by public utility sellers in 
California.
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    \1\ San Diego Gas & Electric Company, et al., 92 FERC para. 
61,172 (2000), reh'g pending (August 23 Order).
    \2\ See Order Directing Staff Investigation, 92 FERC para. 
61,160 (2000) (July 26, 2000 Order).
    \3\ In addition to the Staff Report to the Federal Energy 
Regulatory Commission on Western Markets and the Causes of the 
Summer 2000 Price Abnormalities--Part 1, November 1, 2000 (Staff 
Report), the Commission has placed in the record the transcript of 
the Commission's September 12, 2000 public meeting in San Diego, 
California, written submissions in response to that public 
conference, and all reports prepared by the ISO and PX and their 
market surveillance committees.
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    The Commission finds in this order that the electric market 
structure and market rules for wholesale sales of electric energy in 
California are seriously flawed and that these structures and rules, in 
conjunction with an imbalance of supply and demand in California, have 
caused, and continue to have the potential to cause, unjust and 
unreasonable rates for short-term energy (Day-Ahead, Day-of, Ancillary 
Services and real-time energy sales) under certain conditions. While 
this record does not support findings of specific exercises of market 
power, and while we are not able to reach definite conclusions about 
the actions of individual sellers, there is clear evidence that the 
California market structure and rules provide the opportunity for 
sellers to exercise market power when supply is tight and can result in 
unjust and unreasonable rates under the FPA. Under such conditions, the 
Commission is obligated under FPA section 206 to take action to 
establish market rules, regulations and practices that will ensure just 
and reasonable rates in the future.\4\ Accordingly, we herein propose 
fundamental modifications to the wholesale market structure and rules 
currently in place in California; we also propose price mitigation 
measures to ensure that wholesale rates remain just and reasonable 
during the period it will take to effectuate the market structure and 
market rule changes being proposed. Rates charged by public utilities 
for sales into the ISO's markets and into the PX's day-ahead and hour-
ahead markets will remain subject to the refund conditions set forth in 
the August 23 order, as discussed more fully below.\5\
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    \4\ Under section 206(a) of the FPA, if the Commission finds, 
after hearing, that any rate, charge, or classification for 
jurisdictional services, or any rule, regulation, practice, or 
contract affecting such rate, charge or classification ``is unjust, 
unreasonable, unduly discriminatory or preferential, the Commission 
shall determine the just and reasonable rate, charge, 
classification, rule, regulation, practice, or contract to be 
thereafter observed and in force, and shall fix the same by order.''
    \5\ Because the market structure and market design remedies 
ordered herein may take up to 24 months to effectuate, and the 
refund period permitted by FPA section 206 is limited to 15 months, 
the Commission proposes to condition its market rate authorizations 
for public utility sellers to the ISO and PX on continuing the 
refund obligation through December 31, 2002.
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    In developing the proposed remedies in this order, the Commission's 
goal has been to balance, on the one hand, holding overall rates to 
levels that approximate competitive market levels for the benefit of 
consumers, with, on the other hand, inducing sufficient investment in 
capacity to ensure adequate service for the benefit of consumers. We 
believe that a well functioning competitive wholesale power market in 
California, which includes a well functioning regional transmission 
grid, is a fundamental part of the solution to the supply problems and 
price volatility in California. The interstate, wholesale nature of 
electric markets in California and adjoining states makes it incumbent 
that we take whatever steps we can to make markets in the region work 
for the ultimate benefit of consumers--assuring a reliable supply of 
energy at the lowest reasonable rate.
    The Commission has also had to grapple with a number of issues that 
involve the line between State-Federal

[[Page 67041]]

jurisdiction. There are two aspects to this. First, many, but not all, 
of the defects in the California markets are within this Commission's 
jurisdiction. However, certain matters significantly affecting the 
operation of the wholesale as well as the retail markets in California 
are within the jurisdiction of the State of California. We therefore 
include in this order a discussion of matters that need to be corrected 
by State regulators if there are to be competitive, well functioning 
markets in California, and if California consumers, are to be protected 
in the future. We urge the State to continue working to address these 
matters within its jurisdiction as expeditiously as possible. Second, 
during the past several years this Commission has struggled to 
accommodate, and where possible defer to, the State's initial decisions 
on restructuring, including its decisions directly impacting matters 
within our exclusive jurisdiction under the FPA. However, we have 
reached a point where we must make some difficult choices with respect 
to matters within our exclusive jurisdiction, and we conclude that 
certain defects in wholesale markets must be remedied even if our 
decisions preempt certain decisions previously made by the State in its 
initial restructuring legislation and orders. Unless we take these 
steps, we believe we will be abdicating our responsibility under the 
Federal Power Act to ensure just and reasonable rates and service by 
public utility sellers of wholesale energy in California.
    The immediate remedies proposed in this order include:
     The elimination of the requirement that the three 
investor-owned utilities (IOUs)--Pacific Gas and Electric Company 
(PG&E), Southern California Edison Company (SoCal Edison), and San 
Diego Gas & Electric Company (SDG&E)--must sell into and buy from the 
PX;
     The addition of a penalty charge for deviations in 
scheduling in excess of five percent of an entity's hourly load 
requirements and the disbursement of penalty revenues to the loads that 
scheduled accurately;
     The establishment of independent, non-stakeholder 
Governing Boards for the PX and the ISO; and
     The establishment of generation interconnection 
procedures.
    We also identify a number of structural reforms that must be 
addressed, including:
     The submission of a congestion management redesign 
proposal;
     Possible changes to the auction mechanisms;
     Improved market monitoring and market mitigation 
strategies;
     Demand response programs by the ISO and Scheduling 
Coordinators;
     Elimination of the requirement for balanced schedules; and
     New approach to reserve requirements.
    To ensure fair prices while these market reforms are being put in 
place, the order proposes additional temporary measures to mitigate 
prices, including modification of the single price auction so that bids 
above $150/MWh cannot set the market clearing price that is paid to all 
bidders; imposition of comprehensive reporting and monitoring 
requirements for sellers bidding above $150/MWh; and retention of a 
refund remedy for sales from October 2000 through December 2002.
    The order also recognizes that, to resolve the problems facing 
California consumers, the Public Utilities Commission of the State of 
California (California Commission) and others must address the 
following issues:
     Delays in siting additions of generation and transmission 
capacity;
     Implementation of additional demand response programs at 
the retail level; and
     Elimination of impediments on Load Serving Entities 
pursuing power supplies on a forward basis.
    The Commission has concluded that the hearing we ordered on August 
23 does not need to be a trial-type hearing. Rather, the issues raised 
in this proceeding can be resolved based on written comments and 
evidence and oral presentation directly to the Commission. The 
Commission will permit all interested persons that have not already 
intervened in these dockets to intervene, and allow all interested 
persons to file comments on the proposed remedies and any additional 
information or evidence, by November 22, 2000. We also will hold a 
public conference on November 9, 2000, which will provide interested 
persons the opportunity to discuss the proposed remedies before the 
Commission.

Background

A. California Restructuring

    Efforts to restructure the California electric industry began in 
1994 in response to high electricity prices.\6\ Extensive hearings and 
negotiations in proceedings before the California Commission resulted 
in a final restructuring order issued in December 1995 \7\ and led to 
the unanimous enactment of Assembly Bill 1890 by the California 
legislature in September 1996.\8\ The main points of AB 1890 included 
(1) creation of an ISO and PX by January 1998 and simultaneous 
initiation of direct access; (2) creation of the California Electricity 
Oversight Board (Oversight Board) with members appointed by the 
Governor and legislature; \9\ (3) a competitive transition charge (CTC) 
for the recovery of the IOUs' stranded costs; and (4) a 10 percent rate 
reduction for residential and small customers, and a rate freeze for 
all retail customers.
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    \6\ As of January 1995, retail rates in California were 10 to 11 
cents per kilowatt-hour, approaching twice the national average, and 
rising. See California Rides the Tiger, Public Utilities 
Fortnightly, January 1, 1995, p. 20.
    \7\ See California Commission Decision D.95-12-063 (Dec. 20, 
1995), modified by D.96-01-009 (Jan. 10, 1996) and D.96-03-022, 166 
P.U.R. 4th 1 (California Commission Restructuring Decision).
    \8\ AB 1890, signed by Governor Wilson on September 23, 1996, 
California Statutes 1996, Chapter 854 (Restructuring Legislation or 
AB 1890).
    \9\ As discussed later in this order, the Commission rejected 
elements of the proposal dealing with the Oversight Board, and the 
Board subsequently filed a petition for declaratory order requesting 
that the Commission declare that a bill pending in the California 
Senate (SB 96), modifying the Board's duties under the Restructuring 
Legislation, if enacted, would resolve the Commission's concerns 
about the Board's role.
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    PG&E, SoCal Edison, and SDG&E submitted filings to this Commission 
in April 1996 seeking approval for those aspects of the restructuring 
subject to FERC's jurisdiction, namely, the conveyance of operational 
control of transmission facilities to the ISO,\10\ the authority to 
sell energy at market-based rates through the PX, and approval of the 
overall framework for establishment of the ISO and PX, and for the 
jurisdictional split between the transmission and local distribution 
facilities of the utilities. In a series of orders issued that Fall, 
the Commission largely accepted the filings, and provided a preliminary 
assessment of the adequacy of the utilities' market power analyses.\11\
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    \10\ The Commission established the principles for ISOs in Order 
No. 888, and three other ISOs are in operation today: PJM 
Interconnection, New York ISO, and ISO New England.
    In December of 1999, the Commission issued its Order on Regional 
Transmission Organizations, Order No. 2000. Regional Transmission 
Organizations (RTOs) can be formed as ISOs or may take another 
organization form, such as a transco. The Commission's RTO 
requirements build upon the ISO principles of Order No. 888 and 
reflect, in large measure, the Commission's experience with the 
pioneering efforts of ISOs such as the California ISO. The 
California ISO and its public utility members are required to make a 
filing in compliance with Order No. 2000 on January 17, 2001.
    \11\ See Pacific Gas and Electric Co., et al., 77 FERC para. 
61,077 (1996) (PG&E I); Pacific Gas and Electric Co., et al., 77 
FERC para. 61,204 (1996) (PG&E II); Pacific Gas and Electric Co., et 
al., 77 FERC para. 61,265 (1996) (PG&E III). One area of particular 
concern for the Commission was the scope of the Oversight Board's 
functions. Specifically, the Commission noted that it could not 
``accept a permanent role for the Oversight Board in the governance 
or operation of the ISO, or appellate review of ISO Board decisions, 
because these matters are within our exclusive jurisdiction.'' See 
PG&E II at 61,818.

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    In March 1997, the ISO and PX submitted filings constituting Phase 
II of the restructuring proposal, consisting of organizational and 
governance documents and an Operating Agreement and Tariff for each, a 
Transmission Control Agreement, and other materials and explanations 
required by the Commission in earlier orders. In response to a July 30, 
1997 order by the Commission directing the ISO and PX to file restated 
Tariffs, Agreements and Appendices, they submitted on August 15, 1997 
filings with numerous additional materials. The Commission addressed 
these filings in an order dated October 30, 1997, conditionally 
authorizing limited operation of the ISO and PX.\12\ Since the ISO and 
PX have commenced commercial operations, the Commission has devoted 
significant resources to many proceedings involving the ISO and PX, 
including 30 separate amendments to the ISO's tariffs to address, in 
large measure, the difficulties faced by the ISO in implementing the 
requirements imposed by AB 1890 and the California Commission.\13\
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    \12\ Pacific Gas and Electric Co. et al., 81 FERC para. 61,122 
(1997) (October 30, 1997 Order).
    \13\ Among the four jurisdictional ISOs that are in operation, 
the Commission has devoted, by far, the most resources to the 
California ISO, and most of the attention required by the California 
ISO reflected the difficulties in implementing the requirements of 
AB 1890 and the impact of those requirements on transmission grid 
operations and market performance.
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    Shortly after the ISO and PX commenced operations on March 31, 
1998, the ISO witnessed dramatic spikes in the price for certain 
ancillary services, and did not receive sufficient bids for others, 
events that were inconsistent with the operation of efficient 
markets.\14\ After analyzing reports prepared by market monitoring 
committees and comments from numerous parties, the Commission, among 
other things, directed the ISO to file a comprehensive proposal to 
redesign its Ancillary Services markets.\15\ This redesign has been 
implemented over a period of 24 months, and certain elements have yet 
to be proposed to the Commission for approval.\16\
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    \14\ See AES Redondo Beach, L.L.C., et al., 84 FERC para. 61,046 
(1998), order on reh'g, 85 FERC para. 61,123 (1998) (October 28 1998 
Order), order on further reh'g, 87 FERC para. 61,208 (1999) (May 26, 
1999 Order), order on further reh'g, 88 FERC para. 61,096 (1999), 
order on further reh'g, 90 FERC para. 61,148 (2000). See also 
California Independent System Operator Corporation, 84 FERC para. 
61,309 (1998).
    \15\ October 28, 1998 Order, 85 FERC at 61,462.
    \16\ See May 26, 1999 Order, 87 FERC at 61,801-02 (explaining 
that the ISO developed a phased approach to the redesign).
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    The ISO sought price caps as a solution for the volatility and 
thinness in its Ancillary Services markets. In the July 17, 1998 Order, 
we authorized the ISO to reject bids in excess of whatever price levels 
it believed were appropriate for the ancillary services it procures. On 
rehearing, we explained that, as the procurer of ancillary services, 
the ISO had the discretion to reject excessive bids. We also stated 
that a purchase price cap is not an ideal approach to operating a 
market and that we did not expect the cap to remain in place on a long-
term basis.\17\ In order to make the Imbalance Energy market similarly 
situated to the Ancillary Services markets, we later authorized the ISO 
to adopt a purchase price cap for its Imbalance Energy market at 
whatever level it deemed necessary and appropriate.\18\
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    \17\ 85 FERC at 61,463.
    \18\ California Independent System Operator Corporation, 86 FERC 
para. 61,059 (1999).
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    In our order approving the ISO's Ancillary Services market redesign 
proposal, we allowed the ISO to retain its authority to specify 
purchase price caps for Ancillary Services and Imbalance Energy until 
November 15, 1999.\19\ The ISO had proposed to raise and eventually 
eliminate existing price caps on Ancillary Services and Imbalance 
Energy upon the implementation of several redesign elements, but in the 
interim, it planned to maintain the current $250 price caps. The ISO 
had also proposed a safety net in which it would continue to monitor 
the markets, and if it identified market failures or supply 
insufficiencies, it would lower price caps in the affected markets. We 
directed the ISO to eliminate the price caps by November 15, 1999, with 
the caveat that the ISO could file for an extension of its price cap 
authority if its experience with the market reforms over the summer 
indicated serious market design flaws still existed.
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    \19\ 87 FERC at 61,817-19.
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    On September 17, 1999, the ISO filed proposed tariff revisions to 
extend for one year, until November 15, 2000, its authority to cap 
Ancillary Services and Imbalance Energy prices. By direction of the 
ISO's Governing Board, the price caps were raised from $250 to $750, 
effective September 30, 1999. The proposal gave the ISO the discretion 
to lower the price caps to $500 effective June 1, 2000, if the ISO 
Governing Board determined that any of three specific conditions were 
met. The proposal also gave the ISO discretion to lower the price caps 
by an unspecified amount in the event that it determined that the 
markets were not workably competitive. The Commission accepted the 
proposed tariff provisions.\20\
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    \20\ California Independent System Operator Corporation, 89 FERC 
para. 61,169 (1999), reh'g pending.
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B. Events of Summer 2000

    Wholesale electricity prices in California jumped dramatically 
higher this summer with particularly high peaks during the periods May 
21-24, June 12-16, and June 26-30. The price spikes affected all 
markets run by the PX and the ISO. The monthly average unconstrained 
market-clearing price (UMCP) for May in the PX's day-ahead market 
represented a 100 percent increase over May 1999.\21\ The PX's 
constrained day-ahead price (NP15) peaked at $1,099/MWh on June 28, 
2000.\22\ Prices in the ISO's real-time market neared or reached its 
$750 cap twice in May and on 8 occasions in June. The ISO lowered the 
price cap from $750 to $500 on July 1, 2000. Subsequently, on August 7, 
2000, the ISO further reduced the purchase price cap to $250 per MWh.
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    \21\ Price Movements in California Electricity Markets: Analysis 
of May-June 2000 Price Activity, PX Compliance Unit, September 29, 
2000 at 10.
    \22\ Report of California Energy Market Issues and Performance: 
May-June 2000, ISO Department of Market Analysis, August 10, 2000 at 
13.
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    High temperatures and generation outages led the ISO to declare 
system emergencies 39 times between May and August. PG&E had to effect 
rolling black-outs in San Francisco area on June 14. Notably high 
prices were also experienced at trading hubs throughout the Western 
Interconnection. During this summer period, costs of electricity inputs 
began to increase, particularly gas costs at the California border 
which rose from $2/MMBtu in the spring to about $6/MMBtu this summer. 
At the same time, existing gas fired units \23\ were operated at 
unprecedented levels, driving up the price of NOX emission 
allowances from around $6/lb to over $40/lb at the end of August.\24\
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    \23\ Natural gas comprises about 55 percent of California's fuel 
mix.
    \24\ Staff Report at 3-21.
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    Because the retail rate freeze imposed in SDG&E's service area by 
AB 1890 ended in 1999, the very high wholesale prices were passed 
through directly to the utility's retail customers, resulting in 
monthly bills that were up to 200 to 300 percent higher than the prior 
year. PG&E and SoCal Edison, still subject to retail rate freezes, 
report that their cost for wholesale power has exceeded the

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amount recovered in retail rates by billions of dollars.\25\
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    \25\ The two utilities have reported about $4.6 billion in 
unrecovered wholesale costs of which about $2 billion reflects sales 
of electricity sold from generation which they still own.
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    These events have created an environment of distress in the State. 
Probes have been initiated by the California Commission, the Oversight 
Board, and California's Attorney General, in addition to the 
investigation by this Commission discussed below. In August, the 
California Commission put in place a temporary retail rate cap for 
certain small customers of SDG&E, limiting the amount that they must 
pay per month. Subsequently, the California legislature enacted AB-265, 
a retroactive retail cap which expands on the California Commission's 
action. The legislation limits San Diego residential customers' rates 
to 6.5 cents per kWh, and requires the California Commission to 
investigate the purchasing practices of SDG&E. Both retail rate caps 
defer payment of the total amount due to the utility, requiring 
customers to pay the balance of costs paid into the wholesale market 
with interest in the year 2003.
    California's Governor also signed SB 970 into law in early 
September, which will streamline regulatory approval for new power 
plants.\26\ A number of other bills encouraging energy efficiency, 
distributed generation technologies and approval of new generation were 
also enacted.\27\
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    \26\ On September 7, 2000, the California Assembly passed SB 
970, to address the immediate need for certain additional generating 
capacity in the State. SB 970 created an interagency task force 
appointed by the Governor from various California regulatory 
agencies, related federal agencies, and local governments.
    \27\ See Electric Utility Week, Oct. 9, 2000, pp. 5-6.
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    The ISO and PX and the ISO's Market Surveillance Committee (MSC) 
analyzed the pricing anomalies experienced during the summer and came 
to similar conclusions. A preliminary report prepared by the PX dated 
September 29, 2000, found that price spikes were caused by flawed 
market structures and an insufficient supply of power, rather than 
gaming by market participants. Although market conditions created the 
potential for abuses of market power, the PX Report indicated that no 
one group of participants was setting prices. The ISO, similarly, 
reported that during certain operating conditions, suppliers can have 
significant market power, although the underlying causes of high prices 
were structural and operational in nature.

C. Commission Actions in Response

    On July 26, 2000, the Commission issued an order directing a staff 
fact-finding investigation of the conditions in electric bulk power 
markets (including volatile price fluctuations) in various regions of 
the country.\28\ The order asked staff to determine any technical or 
operational factors, regulatory prohibitions or rules (Federal or 
State), market or behavioral rules, or other factors affecting the 
competitive pricing of electric energy or the reliability of service, 
and to report its findings to the Commission by November 1, 2000. 
Later, staff was asked to expedite the investigation as it related to 
California and markets in the Western Interconnection.
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    \28\ See infra, note 2.
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    On July 28, 2000, the Commission issued an order in Docket No. 
EL00-91-000 in response to a complaint filed by Morgan Stanley Capital 
Group Inc. against the ISO, asking the Commission to invalidate the 
ISO's decision to lower the maximum price it was willing to pay to 
sellers of imbalance energy and ancillary services. At the time the 
Morgan Stanley request was filed, the ISO Governing Board had voted to 
lower the ISO's maximum purchase price for these services from $750 to 
$500. Morgan Stanley wanted the Commission to reinstate the $750 
purchase price cap and prevent the ISO Board from further reducing the 
cap. The Commission denied Morgan Stanley's request, finding that the 
ISO's maximum purchase price authority remained acceptable because the 
ISO did not have the authority to require sellers to bid into its 
markets, and thus, could not dictate sellers' prices.\29\
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    \29\ Morgan Stanley Capital Group Inc. v. California Independent 
System Operator Corporation, 92 FERC para. 61,112 (2000) (Morgan 
Stanley).
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    On August 2, 2000, SDG&E filed a complaint in Docket No. EL00-95-
000 against all sellers of energy and ancillary services into the ISO 
and PX markets requested, among other things, that the Commission 
impose a $250 price cap. The August 23 Order denied SDG&E's request 
because the company had not provided sufficient evidence to support an 
immediate seller's price cap.\30\ However, the Commission instituted 
formal hearing proceedings under section 206 of the Federal Power Act 
to investigate the justness and reasonableness of the rates of public 
utility sellers in the California ISO and PX markets, and also to 
investigate whether the tariffs, contracts, institutional structures 
and bylaws of the ISO and PX are adversely affecting the efficient 
operation of competitive wholesale power markets in California and need 
to be modified.
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    \30\ 92 FERC at 61,606. (Commissioner Massey dissented on this 
point).
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    On September 12, 2000, the Commission conducted a public meeting in 
San Diego to allow interested persons to give the Commission their 
views on recent events in California's wholesale markets; written 
comments were accepted in Docket No. EL00-107-000. In addition, members 
of the Commission and staff participated in a number of Congressional 
hearings and proceedings conducted by California State authorities 
throughout the summer.
    The staff fact-finding investigation is now completed, and the 
Staff Report has been placed in the official record of this proceeding. 
The Staff Report is generally consistent with the findings of the PX 
and ISO reports. A detailed summary of the Staff Report is attached to 
this order as Appendix D.
    Briefly, the Staff Report identifies three factors that contributed 
to the high prices experienced in California this summer. First, 
competitive market forces played a major role in the run-up of prices 
through significantly increased power production costs combined with 
increased demand due to unusually high temperatures and a scarcity of 
available generation resources throughout the West and California in 
particular.
    In addition, the Staff Report concludes that existing market rules 
along with some flawed retail regulatory policies exacerbated the 
situation. The Staff Report notes that the requirement placed upon the 
three IOUs by the California Commission to buy and sell all their 
energy needs through the PX, coupled with the California Commission's 
restrictions on their ability to forward contract, exposed the three 
IOUs to the volatility of the spot market without the ability to 
mitigate this summer's price volatility. The Staff Report also notes 
that a lack of demand responsiveness on the part of retail load allows 
prices to rise well above competitive levels when demand is high and 
supplies are scarce. Finally, the Staff Report finds that the ISO's 
policies relating to replacement reserves increased the amount of 
demand and supply that appears in the ISO's real-time market 
(underscheduling in the PX), which results in operational and 
reliability problems for the ISO and increased costs. The Staff Report 
recommends that the Commission eliminate these flawed market rules.
    Lastly, the Staff Report notes that there is evidence suggesting 
that sellers

[[Page 67044]]

had the potential to exercise market power (where market power is 
defined as prices above short-run marginal cost) this summer; however, 
the data analyzed in the Staff Report and the limited time available 
were not sufficient to make determinations regarding the exercise of 
market power by individual sellers.\31\ One of the Staff Report's 
proposed changes to the market rules would eliminate the single price 
auction rule.\32\
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    \31\ The Staff Report concluded that: ``Further study of high-
priced bidding by individual firms or periods when individual 
generators were not running would be needed to substantiate any 
charges of market power abuse.'' Staff Report at 5-19. The 
Commission will evaluate any information it receives as part of its 
review of these markets.
    \32\ A single price auction pays all bidders the price paid to 
the last seller whose output is needed to clear the market (balance 
supply and demand); often referred to as the market clearing price. 
Another auction mechanism, often referred to as the ``as bid'' 
auction, pays bidders their own bid price if they are selected.
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D. Docket No. ER00-3461-000

    On August 22, 2000, the PX filed Tariff Amendment No. 19 in Docket 
No. ER00-3461-000, proposing to impose maximum prices on Demand and 
Supply Bids in its Day-Ahead and Day-of Markets of $350/MWh. The PX 
states that the $350/MWh limit represents the sum of the $250/MWh price 
limitation on ISO purchases of Imbalance Energy plus the $100/MW amount 
the ISO pays for Replacement Reserves. The PX also states that the 
establishment of equivalent maximum prices in both the ISO and PX 
markets will remove any possible uncertainty that might potentially 
encumber the operation of either of these markets. The PX requests that 
Amendment No. 19 be granted the earliest possible effective date but no 
later than sixty days after filing. By letter dated October 5, 2000, 
Commission staff requested, within fifteen days, additional information 
from the PX to support the need for their proposed caps. On October 19, 
2000, the PX filed additional information (PX Deficiency Report) 
analyzing six months of recent PX market data demonstrating that the 
ISO's real-time market serves as a de facto price cap in the PX day-of 
markets. Two exceptions occurred on June 27 and June 28.
    Notice of the PX's filing was published in the Federal Register, 65 
FR 57,599 (2000), with motions to intervene and protests due on or 
before September 12, 2000. The California Commission filed a notice of 
intervention. Timely motions to intervene, comments, and protests were 
filed by the entities listed in Appendix A. In addition, Williams 
Energy Marketing & Trading Company (Williams) and the Oversight Board 
filed untimely motions to intervene.
    The California Commission, the Oversight Board, PG&E, and SoCal 
Edison support the filing and request its approval as an interim 
measure until additional steps are taken to restore prices to just and 
reasonable levels. Other intervenors argue that the filing should be 
rejected because: (1) The PX has provided virtually no justification 
for its proposed price cap; (2) the proposal would further intrude into 
the competitive energy markets and should be deferred; and (3) the PX's 
proposal is inconsistent with the Commission's findings in Morgan 
Stanley. Power marketers also argue that price caps are unnecessary and 
harmful to the development of a competitive electric market by 
jeopardizing investment in generation and creating an atmosphere of 
extreme uncertainty.

E. Docket No. ER00-3673-000

    On September 14, 2000, the ISO filed Tariff Amendment No. 31 in 
Docket No. ER00-3673-000, proposing to remove the November 15, 2000 
termination date of the ISO's purchase price cap authority. The ISO 
states that the proposed Amendment No. 31 would remove the existing 
termination date of the ISO's authority to disqualify Ancillary Service 
and Imbalance Energy bids that exceed levels specified by the ISO and 
would confirm the ISO's authority to establish bid caps for all of its 
markets. The proposed amendment does not specify the particular level 
of the purchase price caps; instead, it preserves the discretion of the 
ISO to adjust the bid cap levels as appropriate. The ISO requests that 
Amendment No. 31 become effective as of the date the existing provision 
for bid cap authority expires on November 15, 2000.
    Notice of the ISO's filing was published in the Federal Register, 
65 Fed. Reg. 57,599 (2000), with motions to intervene and protests due 
on or before October 5, 2000. The California Commission filed a notice 
of intervention. Timely motions to intervene, comments, and protests 
were filed by the entities listed in Appendix B. In addition, the City 
of San Diego (San Diego) filed an untimely motion to intervene.
    Eight intervenors filed comments supporting the amendment to extend 
the ISO's bid cap authority, stating that because the market is not 
currently workably competitive, purchase caps are necessary. Twelve 
intervenors protest Amendment No. 31, stating that purchase price caps 
and the indiscriminate lowering of such caps threatens reliability, 
creates massive instability, and discourages investment in and 
development of new generation resources. In addition, these intervenors 
object to the ISO's proposal to set bid caps and as a corollary reject 
bids above the cap, instead of setting a purchase price at which they 
are willing to buy. Intervenors maintain that such an ability to reject 
bids would lead to the unilateral ability of the ISO to reduce the 
generator's bid to the price it is willing to pay, and amounts to 
setting the seller's price in violation of our precedents. Finally, 
intervenors state that the ISO has not developed specific criteria for 
the application and level of purchase price caps.
    On October 20, 2000, the ISO filed an answer arguing that the 
protests lack merit.

Interventions and Other Pleadings

    As noted in the August 23 Order, any party that intervened in 
Docket No. EL00-95-000 is considered to be a party in this consolidated 
hearing proceeding.\33\ The following filed motions to intervene out-
of-time in Docket Nos. EL00-95-000 and/or EL00-98-000: the Cogeneration 
Association of California jointly with the Energy Producers and Users 
Coalition (CAC/EPUC); the Cities of Anaheim, Azusa, Banning, Colton, 
and Riverside, California (Southern Cities); the City of Vernon, 
California, (Vernon); San Diego; the California Large Energy Consumers 
Association (CLECA); and Puget Sound Energy, Inc. (Puget Sound).
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    \33\ August 23 Order at 61,606.
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    On October 16, 2000, PG&E, SoCal Edison, and The Utility Reform 
Network (TURN) (collectively, Joint Movants) filed a joint motion for 
emergency relief and further proceedings. Joint Movants request that 
the Commission: (1) Make an immediate finding that California's 
electricity markets are not producing just and reasonable rates, (2) 
put in place an interim $100/MWH price cap, (3) direct public utility 
sellers to provide cost-of-service information for the purpose of 
implementing market power mitigation measures, and (4) institute 
expedited procedures to develop long-term market power mitigation 
measures and to determine refund responsibility. SDG&E filed comments 
in support of the motion, but urging that fundamental reforms proceed 
expeditiously.
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    \34\ On October 26, 2000, the ISO Board voted to change the ISO 
bid cap from the current $250 level to a load differentiated cap, 
effective on November 3, 2000 or as soon thereafter as can be 
implemented. Our action in this order freezing the ISO bid cap at 
the current $250 level for 60 days, renders the ISO board vote null 
and void.
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    The California Commission also filed a motion for interim relief, 
on October 19, 2000, proposing that FERC require certain generators and 
marketers to offer specified amounts of capacity under forward 
contracts at FERC-approved

[[Page 67045]]

cost-based rates. The following day, the ISO submitted a proposed offer 
of settlement to impose: (1) A $100/MWh price cap with a list of 
exceptions; (2) requirements for load-serving entities to forward 
contract; and (3) charges against load and generation not adhering to 
forward scheduling requirements.
    Various entities have filed motions and pleadings proposing their 
own preferred remedies and mitigation such as a $100 bid cap, 
reintroduction of cost-based rates, and tiered bid caps.\34\ Our 
decision is informed by these requests and proposals and we incorporate 
into our actions the aspects of those proposals which achieve our 
objectives. We inform these parties that they should renew in their 
November 22 comments any concerns stemming from our decision to propose 
these remedies.
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    \34\ On October 26, 2000, the ISO Board voted to change the ISO 
bid cap from the current $250 level to a load differentiated cap, 
effective on November 3, 2000 or as soon thereafter as can be 
implemented. Our action in this order freezing the ISO bid cap at 
the current $250 level for 60 days, renders the ISOo board vote null 
and void.
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Procedural Matters

    In view of the early stage of the consolidated hearing proceedings 
and the absence of any undue prejudice or delay, we find good cause to 
grant the untimely, unopposed motions to intervene of CAC/EPUC, 
Southern Cities, San Diego, Vernon, CLECA, and Puget Sound. Appendix C 
lists all parties to this proceeding. In addition, the Commission will 
permit all interested persons that have not already intervened in these 
dockets to intervene and file comments by November 22, 2000.
    Also, in view of the early stage of the proceeding and the absence 
of any undue prejudice or delay, we find good cause to grant Williams' 
and the Oversight Board's late interventions in Docket No. ER00-3461-
000, and San Diego's late intervention in Docket No. ER00-3673-000.
    We will reject the ISO's answer in Docket No. ER00-3673-000 to the 
extent that it represents an impermissible answer to protests. See 18 
CFR 385.213(a)(2) (2000).

Discussion

    The Commission is obligated under the FPA to ensure that the rates, 
terms and conditions of wholesale sales and transmission in interstate 
commerce by public utilities are just, reasonable and not unduly 
discriminatory or preferential. Under section 206 of the FPA, if the 
Commission finds that rates, charges or classifications for 
jurisdictional services, or rules, regulations, practices or contracts 
affecting such rates or charges, are not just and reasonable, or are 
unduly discriminatory or preferential, the Commission must determine 
the just and reasonable rate, charge, classification, rule, regulation 
or practice to be in effect. In exercising this responsibility in 
today's electric industry environment, the Commission is faced with 
electric markets that are increasingly interstate in nature and 
increasingly dependent upon one another, and with markets that are in 
varying stages of transition to competition at the wholesale and, in 
numerous states, the retail level. With respect to California, we are 
faced with a complex transition from one regulatory regime to another 
and efforts to establish competitive markets at both the wholesale and 
retail levels. In this particular proceeding, our responsibility is to 
determine whether public utility sellers to the ISO and PX are charging 
unjust and unreasonable rates, and whether the market structures and 
market rules governing public utility wholesale sellers in California, 
and affecting the wholesale rates of such public utility sellers, are 
resulting in, or have the potential to result in, wholesale rates that 
are unjust, unreasonable, unduly discriminatory, or preferential. In 
particular, we are concerned about whether these market structures and 
rules, particularly in conjunction with an imbalance of supply and 
demand, may give public utilities the ability to exercise market power 
and thereby charge unjust and unreasonable rates.
    Before discussing the specific aspects of market structure and 
rules that may be adversely affecting wholesale rates, we believe it is 
important to provide an overview of the historical context in which we 
address these issues. In 1996, when California decided to embark on its 
bold and innovative restructuring initiative, it did so because it 
recognized the problems inherent in its existing regulatory model. 
Prices paid by retail consumers were among the highest in the nation. 
California was becoming increasingly dependent on out-of-state 
generating resources to meet the needs of its citizens. It was against 
this backdrop of existing problems that California decided to pursue a 
more market-oriented approach to the provision of retail electricity 
service--ordering its three IOUs to divest ownership of their 
generation assets, requiring that they turn over operational control of 
their transmission facilities to the ISO, establishing the centralized 
power exchange, and adopting a market design with elaborate rules to 
govern the behavior of participants in this newly created electricity 
market.
    Although well intentioned, and in some ways visionary, California's 
pioneering of retail electricity restructuring has not always produced 
a result that its architects intended--electricity prices lower than 
historical levels for retail consumers. Indeed, the deregulatory 
approach adopted by California not only failed to address many of the 
existing problems which were plaguing the State, but in many ways it 
exacerbated and magnified those problems. This is not meant to cast 
blame, but to recognize and try to learn from some of the mistakes that 
were made. At the Federal level, we remain convinced that competitive 
markets will provide efficiencies and lower electricity prices to 
consumers--both retail and wholesale. But such markets need to be 
properly designed and administered in an independent and non-
discriminatory fashion, and they must recognize and accommodate the 
regional, interstate nature of electricity trade.
    The events of this summer provide dramatic evidence of the 
interstate nature of electric systems and markets in the Western 
Interconnection. California is not an electrical island. Operationally, 
the transmission facilities currently controlled by the ISO are part of 
the much larger Western Interconnection.\35\ The reliability of 
California's electric system depends on access to generating resources 
located throughout the Western Interconnection.\36\ Decades ago, 
western utilities made large investments in high voltage interstate 
transmission lines to support the market efficiencies resulting from 
seasonal diversities between the northern and southern markets. Over 
time, California utilities have increasingly relied on imports from 
generation located in neighboring states to meet their load 
requirements and have constructed significant transmission interties to 
import electricity for California consumers.\37\ This summer, exports 
from California to others increased. Therefore, the

[[Page 67046]]

operation of the California electricity market can affect prices 
throughout the entire Western Interconnection. The Staff Report 
demonstrates that during the summer of 2000 correlations between PX 
prices and Western market bilateral prices were quite strong.\38\
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    \35\ As early as the 1970's, Western utilities began to face the 
problem of significant regional loop flows resulting from the 
interstate use of the Western grid and, in the 1990's, Western 
utilities agreed on a regional response. See Southern california 
Edison Co., et. al., 70 FERC para. 61,078 and 73 FERC para. 61,219 
(1995).
    \36\ California's import capability is approximately 8,000 MW.
    \37\ Two of the first trading hubs for wholesale electricity 
futures were founded at the California Oregon Border (COB) and at 
Palo Verde, in Arizona, because of the significant amounts of 
interstate market activity that occurs at these points.
    \38\ See Staff Report at 1-3, 3-15--3-17.
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    We make these observations to provide some context for the actions 
we are proposing in this order. We commend and continue to support 
California's efforts at restructuring its electricity markets to try 
and bring lower prices to consumers in California. Although 
California's restructuring initiatives directly implicated matters 
subject to our jurisdiction, in order after order, we have deferred 
wherever possible to the restructuring decisions made by the State. We 
have devoted unprecedented resources to try and make the California 
initiative a success. Ultimately, however, the Commission must ensure 
that wholesale market rules and institutions--even those created by 
state action--result in just and reasonable wholesale rates for 
electricity. This summer's events in California and our subsequent 
investigation have convinced us that we must take decisive action under 
section 206 of the Federal Power Act to remedy fundamental problems 
that have been identified in the California market design. The 
California experience has highlighted the dangers of hard-wiring a 
market design that is inflexible and cannot adapt to needed changes.
    It is important to get the fundamentals right and to devise a 
roadmap that takes into account the needs of the market and the 
regional implications of electricity trade. In many ways, this is the 
approach that Order No. 2000 has taken with regard to the formation of 
Regional Transmission Organizations. But Order No. 2000 avoided being 
overly prescriptive and even went so far as to adopt a requirement of 
open architecture to ensure that RTOs could adapt and evolve to meet 
the changing needs of the marketplace. Market rules and institutions 
need to be flexible so that they support the natural evolution of the 
marketplace. In California, we are confronted with a situation where 
market participants have to work around overly prescriptive market 
institutions and requirements which have become an impediment to the 
efficient operation of the marketplace and which have harmed consumers. 
The existing market has not lowered prices to consumers this summer nor 
stimulated needed investment in new generation and transmission 
facilities.
    The specific reforms we are proposing in this order are limited to 
fixing the fundamental problems which have been identified. As we move 
forward, we will need input from California and other Western State 
policymakers to help shape and further develop this new market design. 
But such input should recognize the regional, interstate character of 
the western marketplace. We expect the new non-stakeholder boards which 
we are ordering below to consider further refinements and to help guide 
the continued evolution of the market. But the Commission must take 
action at this juncture under section 206 of the Federal Power Act to 
remedy the problems that have been found to exist in the California 
market structure. This action must be taken to ensure that the high and 
volatile prices experienced this past summer do not recur to the 
detriment of consumers in California and in the West generally. In this 
order, we focus on proposing changes to certain rules and policies of 
the PX and the ISO that we believe contributed to the high prices which 
California experienced last summer.\39\
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    \39\ There are a number of fixes that must be made that are 
beyond the statutory authority of this Commission. Thus, we also 
highlight several initiatives that the State of California must 
undertake to ensure that the high and volatile price scenario of 
this past summer is not repeated.
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A. Overview

    One of the primary Congressional goals in enacting Part II of the 
Federal Power Act was to protect electric ratepayers from exercises of 
market power. Ratepayer interests generally centered on ensuring that 
rates were not excessive or unduly discriminatory. The need to ensure 
an adequate supply of generation usually was met through requirements 
imposed by states on franchise utilities to build or buy adequate power 
resources to meet demand consistently. Today, however, in states such 
as California, the adequacy of local power resources depends, not just 
on state requirements, but also on whether market prices are sufficient 
to elicit adequate supplies, through construction or otherwise. In 
other words, when supply is driven by market price instead of 
regulatory requirements, ratepayer interests may no longer depend 
solely on whether current prices are deemed too high, but also on 
whether prices are too low to elicit new supplies over time.
    As indicated by the Staff Report and by reports prepared by 
California State agencies and others, this summer's wholesale markets 
exhibited certain market fundamentals that would be expected to cause 
prices to rise. Input costs increased as the cost of fuel, emission 
credits and O&M expenses increased.\40\ Sustained demand increased, 
requiring increased reliance on generating resources that would have 
been more expensive to operate even if input prices had not 
increased.\41\ Conditions in the Northwest decreased amounts of 
hydropower supply usually available to the market which, combined with 
a failure to bring new generation into service over the last decade, 
resulted in a true scarcity of generation.\42\ In circumstances like 
this, prices are expected to rise--and indeed they must rise to induce 
the investment in new capacity that is needed to serve customers 
adequately.
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    \40\ Staff Report at 3-20--3-22.
    \41\ Id. at 5-2, 5-3, and 5-6.
    \42\ Due to reduced water flows in the West, the output of 
hydropower generation was reduced. For example, hydro output in June 
1999 was 16,685 GWh and in June 2000 was 12,808 GWh, a reduction of 
3,880 GWh. Staff Report at 2-26.
---------------------------------------------------------------------------

    The issue raised in this proceeding is whether dysfunctional market 
rules or the exercise of market power allows prices to rise above just 
and reasonable levels. We conclude that certain market rules do 
interfere with the functioning of the market and, taken together, may 
permit sellers to exercise market power. Accordingly, these market 
rules must be revised. Many of the market dysfunctions in California 
and the exposure of California consumers to high prices can be traced 
directly to an over reliance on spot markets. Industries that are 
either capital intensive or that have a lack of demand response do not 
rely solely on spot markets where volatility is to be expected. Because 
the price risks inherent in spot markets are too great for both 
suppliers and consumers, these market sectors will prefer to manage 
their risk profiles through forward contracts. However, in California, 
certain market rules imposed by AB 1890 and its implementation by the 
California Commission (e.g., mandatory buy-sell through the PX) 
prevented the IOUs from engaging in forward contracts to any 
significant degree. And other retail suppliers who would have been free 
to implement appropriate risk management strategies could not be 
induced to participate in California's market because the low retail 
rate, frozen at 10 percent below historical levels, thwarted 
competitive opportunities for new participants to enter the market.\43\ 
Even so, until the market was stressed this summer by extreme events, 
pricing volatility was

[[Page 67047]]

isolated and short-lived and wholesale prices were so low that stranded 
costs were paid off more quickly than expected. The significant 
failings of this market design became apparent only as peak demand 
outstripped supply.
---------------------------------------------------------------------------

    \43\ An Analysis of the June 2000 Price Spikes in the California 
ISO's Energy and Ancillary Services Markets, ISO Market Surveillance 
Committee, September 6, 2000 at 13.
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    An essential remedy is the elimination of rules that prevent market 
participants from managing their risks. Moving significant amounts of 
wholesale transactions into forward markets will (1) reduce reliance on 
spot markets, thereby directly reducing both the likelihood and the 
adverse economic consequences of pricing volatility; \44\ (2) eliminate 
the adverse reliability impacts that the ISO faces each day as its 
obligation to operate a real-time balance market has become transformed 
into operating the major commodity exchange at the last minute; (3) 
increase the likelihood of new generation entry because the uncertain 
revenue stream from spot markets will not attract the necessary capital 
investments; and (4) limit the ability of sellers to exercise market 
power in spot markets. To address this critical problem and ensure that 
market participants have access to forward markets, this order proposes 
certain remedies intended to facilitate forward contracting.
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    \44\ We do not seek to eliminate pricing volatility in spot 
markets. These markets will, as a matter of course, swing in 
reaction to changes in short-run market conditions that are 
difficult to predict. What is important is that market participants 
have the ability to protect themselves from the economic 
consequences of pricing volatility. In simplest terms, if California 
IOUs had the option to use forward markets last summer and had 
chosen to exercise those options to purchase most of their needs, 
the high spot market prices experienced this summer would have 
affected only a small portion of the wholesale power costs. We do 
not mean to suggest that spot prices are always higher than forward 
market prices. Indeed, because of cooler than expected weather in 
the east, buyers in PJM that may have locked in prices in forward 
markets, based on the best information at the time of their 
decision, ultimately paid more for energy than the price that was 
available in the spot markets. The crucial issue is choice and 
providing market participants with the tools to access the market in 
the ways that best serve their needs.
---------------------------------------------------------------------------

    A second critical issue we address is the ability of the ISO and PX 
to operate and implement wholesale markets and the ability of the ISO 
to operate a transmission system reliably and efficiently under the 
governance of its stakeholder board of directors. The functioning of 
wholesale markets and the reliability and efficiency of the interstate 
transmission grid cannot be compromised by a decision-making process 
that is overly complex, mired in controversy, or prone to excessive 
influence by special interest groups. Boards, whether comprised of 
stakeholders or non-stakeholders, must be able to respond decisively to 
conditions necessary to maintain system integrity and operation. Most 
importantly, because the markets operated by the PX and the ISO are 
interstate markets and the transmission system operated by the ISO is 
part of an interstate transmission grid, the ISO's decision-making 
process must be responsive to the operations and the welfare of the 
regional marketplace, and not be restricted to the concerns of one 
geographic location or one segment of the market. Based on past 
performance, the ISO and PX boards no longer meet these standards. For 
these reasons, we propose to disband the stakeholder boards and direct 
the establishment of independent boards.
    We propose several other immediate market reforms. We also identify 
certain other longer-term measures which need to be addressed.
    Finally, because the changes we are requiring here will take time 
to implement and the addition of new supply is not imminent, we propose 
price mitigation measures through December 31, 2002. As noted earlier, 
a number of the changes that are required to ensure proper market 
functioning are within the control of state agencies. We have 
identified those critical issues here as well. It is imperative that 
these matters also be addressed during the period when price mitigation 
is in effect.

B. Proposed Immediate Measures

1. Requirement to Sell Into and Buy From the PX
    The California Commission Restructuring Decision required that the 
three IOUs sell all of their generation into and purchase all of the 
energy requirement for their retail load from the PX.\45\ In so doing, 
the California Commission established a mechanism to ensure that the 
IOUs could not withhold generation from the market prior to the 
completion of divestiture and to value in a systematic way the above 
market generation assets which the IOUs had not divested. Sales at 
frozen retail rates in conjunction with purchases at lower market 
prices created a revenue surplus from which to write off stranded costs 
and to transition to a regime of fully competitive prices. The 
requirement, in fact, was to end on the earlier of March 31, 2002, or 
the date when the IOUs had written off all of their stranded costs.\46\
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    \45\ Initially, the PX administered only a Day-ahead and an 
hour-ahead (Day-of) spot Market. Later, it added limited forward 
marketproducts.
    \46\ Section 368 of AB 1890.
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    During the first three years of operation, a confluence of 
favorable temperatures and hydro conditions resulted in such low spot 
market prices that the IOUs were able to write off substantial amounts 
of stranded costs. Because of these conditions and the valuation of 
their divested generation assets, the IOUs have either written off or 
valued virtually all of their stranded costs. However, this past 
summer's experience and the Staff Report make clear that these 
favorable market conditions have evaporated. A robust economy with 
little investment in capacity additions, high temperatures throughout 
the West and little supply response have now resulted in power costs 
above the frozen retail, rate levels.\47\ The IOUs' reliance on the PX, 
and, in particular, the California Commission's requirement that they 
bid the majority (upwards of 80 percent) of their load into the PX's 
day-ahead and hour-ahead spot markets \48\ created substantial short-
term cost exposure and price spikes of such a magnitude that market 
confidence became virtually nonexistent. The details of the Staff 
Report paint a bleak picture of an over reliance on a spot market in a 
circumstance of inadequate supply. Moreover, because the IOUs have now 
divested substantially all of their thermal generation they are 
substantial purchasers of energy.\49\ Therefore, forced sales into the 
PX by the IOUs to prevent withholding are no longer necessary.
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    \47\ The Staff Report indicates that over the past five years 
load in California has risen by 5,522 MW while resources have 
increased only 672 MW. Staff Report at 5-8.
    \48\ While the IOUs have recently been authorized by the 
California Commission to use either the PX's forward markets or the 
bilateral market, the overall restrictions on the total amount of 
forward purchases remain.
    \49\ PG&E, SoCal Edison, and SDG&E still control 26 percent, 20 
percent, and 1 percent, respectively, of in-state generation and 
purchase power contracts.
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    As a result, we conclude that the requirement for the IOUs to sell 
all of their generation into and buy all of their requirements from the 
PX, whether in its spot or forward markets, is a significant factor 
contributing to rates that are unjust and unreasonable,\50\ and we 
propose to declare it null and void effective 60 days from the date of 
this order. Under this proposal, the IOUs may elect to be their own 
Scheduling Coordinator rather than maintaining the current structure 
where the PX is the Scheduling Coordinator for the three IOUs. Without 
this buy/sell restriction on wholesale trade, the IOUs are free to 
pursue a portfolio of long- and short-term resources and access 
whatever wholesale markets are suited to meeting the needs of their 
retail customers

[[Page 67048]]

(including bilateral markets, the PX, and others such as Automated 
Power Exchange, Inc.) or by providing power from their own resources to 
serve their own load and self provide the necessary ancillary 
services.\51\ As an independent exchange, the PX will be free to design 
and offer the services needed by market participants.
---------------------------------------------------------------------------

    \50\ The Staff Report reached a similar conclusion. Staff Report 
at 5-9 and 5-11.
    \51\ The IOUs own nuclear and hydro generation whose variable 
operating cost are approximately $16/MWh (for a nuclear unit 
operating at 88 percent capacity factor) and no fuel costs for 
hydro. Dynegy letter dated October 27, 2000.
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    While we are proposing to remove an encumbrance on wholesale 
trades, we note that, currently, the California Commission restricts 
the IOUs' ability to procure forward products. These restrictions 
prohibit the IOUs from creating mutually beneficial long-term financial 
contracts with generators and marketers, and these prohibitions can 
result in an increase in overall prices, and the volatility of prices, 
to consumers.
2. Underscheduling of Load and Resources
    Reliable and orderly system operations require that load and 
resource schedules be substantially finalized on a day-ahead or day-of 
basis \52\ subject to only minor adjustments to reflect more accurate 
information of actual system conditions as real time approaches. As a 
result, the ISO operates a real-time energy imbalance market to supply 
unanticipated changes in load and resources. This balancing market was 
designed to accommodate approximately 5 percent of the total 
anticipated load.
---------------------------------------------------------------------------

    \52\ The PX Day-of Market is the hourly energy market that is 
scheduled with the ISO at least 2 hours in advance of real time.
---------------------------------------------------------------------------

    The record indicates that there is a chronic pattern of 
underscheduling \53\ load and generation in the PX's Day-Ahead and Day-
of market.\54\ As a result, large amounts of load are not being 
scheduled with the ISO and the ISO is often in the position of 
procuring a substantial amount of energy to meet these needs in real 
time. In some hours the ISO has been faced with acquiring upwards of 
6,000 MW of system energy needs, in real time.\55\ The ISO has reported 
that underscheduling was 50 percent higher this summer than the 
previous two summers. The cost of out-of-market purchases needed to 
balance load at the last minute rose to $100 million this summer 
compared to about $1 million last summer. Underscheduling has caused 
the ISO's operating personnel to call upon energy from capacity that 
had been procured for Operating Reserves. As a result, this reserve 
capacity has been diverted from its intended purpose--protecting 
against the loss of a component of the system. In addition, the 
underscheduling resulted in 39 stage-one and stage-two emergencies 
between June and August 2000, and 13,500 MWhs of load was 
curtailed.\56\ The combination of these problems places even more 
pressure on system operators.
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    \53\ Underscheduling occurs when an entity schedules 
significantly less energy than its expected actual consumption.
    \54\ Staff Report at 5-14 and 5-16.
    \55\ See ____ FERC at   .
    \56\ August 25, 2000 Memorandum from Mr. Winter to ISO Board of 
Governors.
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    As a practical matter, the ISO is often not simply providing the 
real-time services needed to operate a transmission system and balance 
the market, but is actually forced to operate an energy market and to 
become a market participant in order to make last minute purchases as a 
supplier of last resort. The PX Day-Ahead and Day-of Markets were 
designed as spot market exchanges; the ISO's real time market was not 
intended to provide this function. Underscheduling puts system 
reliability at risk and creates a stronger sellers' market and higher 
prices as real time approaches. In an attempt to address this problem, 
we directed the ISO in the August 23 Order to use a more forward 
approach in procuring these energy needs.\57\
---------------------------------------------------------------------------

    \57\ 92 FERC at 61,108.
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    As discussed above, the elimination of the buy/sell requirement in 
the PX will allow for greater discretion for the IOUs to self supply or 
to procure resources in bilateral or other markets for their energy 
requirements as well as necessary ancillary services. We believe that 
the existing underscheduling problem is addressed in part by this 
revision to the market. We propose to temporarily correct the current 
situation by limiting the ISO to only the functions needed to reliably 
operate the transmission system, i.e., provide a balancing service 
rather than running an energy market. To address this reliability 
problem and to ensure that loads do not rely excessively on the ISO as 
the provider of last resort, we propose to establish a penalty charge 
for deviations in excess of five (5) percent of an entity's hourly load 
requirements.\58\ Loads in excess of this deviation band that are not 
scheduled in the Day-Ahead or Day-of Markets will be assessed a penalty 
charge of two times the ISO's real time energy cost for any purchase of 
balancing energy during the hour. The penalty will not exceed $100/MWh 
(i.e., the actual imbalance cost plus $100), which approximates the 
current charge assessed to underscheduled load for replacement 
reserves. As to the penalty, we have long set disincentive rates for 
emergency service at twice the standard rate, and we will apply that 
policy here.\59\ As a further incentive to encourage accurate 
scheduling in the Day-Ahead or Day-of Markets, we propose to direct the 
ISO to disburse at the end of the billing period all penalty revenues 
(revenues above costs) pro rata to the loads that scheduled accurately 
and that did not exceed the 5 percent deviation band for that hour. In 
addition, later in this order we propose to remove one of the financial 
incentives for sellers to favor the real-time market by providing that 
suppliers in the real-time market receive either a capacity payment for 
replacement reserves or energy payments, but not both. We also describe 
later in this order auction modifications that should eliminate the 
need for the ISO to go out of market to procure energy needed for the 
balancing market. As a result, loads when properly scheduled will be 
better able to access required supply. We believe that this more 
orderly process for system operations in conjunction with the ISO's use 
of forward contracts will better enable the ISO to reliably operate the 
transmission system.
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    \58\ We propose 5 percent because this is the maximum amount 
that the ISO intended to balance in the real-time market for 
operating the transmission system.
    \59\ See, e.g., Indiana Michigan Power Company, et al., 44 FERC 
para. 61,313 at 62,078 (1988).
---------------------------------------------------------------------------

    Underscheduling is a symptom of many of the other market flaws.\60\ 
Because our order addresses many of these problems we expect the 
underscheduling problem to subside. The ISO should consider other 
market design changes that would address underscheduling.
---------------------------------------------------------------------------

    \60\ See also Section C3. Balanced Schedules below.
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3. Governance of the PX and ISO
    The Commission conditionally authorized the establishment of the 
ISO and PX in November 1996.\61\ In that order, the Commission noted 
the accelerated schedule for commencement of operations and committed 
to dedicate the necessary resources to accomplish that schedule. The 
Commission also expressed its intent to give great weight to the views 
expressed in the California Restructuring Legislation. The Commission's 
deference is most apparent with respect to the governance of the ISO 
and PX. The parties had proposed that the ISO and PX would be

[[Page 67049]]

governed by boards composed of individuals residing in California who 
were chosen to represent various stakeholder classes (i.e., 
transmission owners, municipal entities, sellers, end-users, etc.), 
with each class having a specified number of voting representatives. 
The Governing Boards would be responsible for broad operating criteria, 
rather than daily decisions and functions, and members were to vote 
individually, not as a class. As initially proposed, the Oversight 
Board was intended to perform two primary functions: (1) Establish 
nominating/qualification procedures for the ISO and PX Governing 
Boards, determine the composition of Board representation, and select 
Board members both initially (Start-Up Function) and in the future; and 
(2) serve as a permanent appeal board for reviewing ISO Governing Board 
decisions.
---------------------------------------------------------------------------

    \61\ PG&E II.
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    The Commission accepted the proposed Governing Boards (as modified 
by the Restructuring Legislation) except for the proposed California 
residency requirement, finding them to be consistent with the ISO 
Principles of Order No. 888.\62\ The Commission relied on the fact that 
no one voting class would be able to block or veto actions and that no 
two classes together would be able to form a sufficient majority to 
make decisions, and on the codes of conduct that would govern board 
members' behavior. In an effort to assist in the advancement of the 
California restructuring process, the Commission granted limited 
authorization to the Oversight Board's Start-Up Function, subject to 
all determinations made by the Oversight Board being filed with the 
Commission for final review.\63\ The Commission, however, was troubled 
by the role for the Oversight Board in the governance and operation of 
the ISO and PX and the appellate review of ISO Board decisions, because 
these matters were--and remain--within our exclusive jurisdiction.\64\ 
Consequently, the Commission stated that the continuing functions of 
the Oversight Board established by the Restructuring Legislation would 
conflict with our statutory duties under the Federal Power Act and 
could not remain a part of the proposal.\65\
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    \62\ See Promoting Wholesale Competition Through Open Access 
Non-discriminatory Transmission Services by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, 61 Fed. Reg. 21,540 (1996), FERC Stats. & Regs. para. 
31,036 (1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 
Fed. Reg. 12,274 (1997), FERC Stats. & Regs. para. 31,048 (1997), 
order on reh'g, Order No. 888-B, 62 Fed. Reg. 64,688, 81 FERC para. 
61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC para. 61,046 
(1998), aff'd in relevant part sub nom. Transmission Access Policy 
Study Group, et al. v. Federal Energy Regulatory Commission, 225 
F.3d 667 (D.C. Cir. 2000).
    \63\ 77 FERC at 61,817-17; 81 FERC at 61,453.
    \64\ See 77 FERC at 61,818.
    \65\ 81 FERC at 61,451-53; see also California Power Exchange 
Corp., et al., 85 FERC para. 61,263 (1998).
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    The Commission recognized, however, that states have a legitimate 
oversight role with respect to traditional retail matters such as: 
protecting the welfare of the state's retail consumers and citizens; 
protecting the reliability of electric service to California retail 
consumers; ensuring the adequacy of the generating and transmission 
resources necessary to achieve designated planning and operating 
reserve criteria to ensure adequate service to end-use consumers; 
monitoring whether the California retail electricity market is a well-
functioning market and delivers the public benefits for which it was 
developed; and ensuring that the ISO and PX keep retail consumers 
adequately informed of matters affecting retail electric consumers. The 
Commission further stated that this role would not conflict with its 
jurisdiction and would address state-jurisdictional matters.\66\
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    \66\ 85 FERC para. 61,264 at 62,068.
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    The Oversight Board subsequently filed a petition for declaratory 
order requesting that the Commission declare that a bill pending in the 
California Senate (SB 96), modifying the Board's duties under the 
Restructuring Legislation, if enacted, would resolve the Commission's 
concerns about its role.\67\ Rather than giving the Oversight Board 
confirmation power over all members of the ISO and PX Boards, SB 96 
afforded the Oversight Board confirmation rights over a limited number 
of members representing primarily end-users, and addressed the 
residency requirement. In addition, the structural composition of the 
Governing Boards was to be modified as soon as another state was to 
participate in the ISO and PX. SB 96 provided that California could 
change the ISO and PX Governing Boards into non-stakeholder boards, 
subject to filing revised Bylaws with the Commission. SB 96 also 
limited the function of the Oversight Board as an appeal board to ISO 
decisions regarding eight distinctly state-retail matters.\68\ In the 
Oversight Board decision, we accepted, as consistent with the FPA, the 
Oversight Board's limited interim appointment function and limited 
appellate review rights set forth in SB 96.
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    \67\ See California Electricity Oversight Board, 88 FERC para. 
61,172 (1999), reh'g denied, 89 FERC para. 61,134 (1999), appeal 
docketed, Western Power Trading Forum, et al., v. FERC, No. 99-1532 
(D.C. Cir.) (Oversight Board).
    \68\ These state-retail matters included, e.g. state functions 
assigned to the ISO and PX under the state law, matters pertaining 
to retail electric service or retail sales of electric energy, and 
open meeting standards and meeting notice requirements.
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    Events over the past two years increasingly have made clear that 
the ISO Governing Board has such difficulty reaching decisions on the 
complex and divisive issues confronting it that it has become 
ineffective. The Staff Report comments on this deficiency.\69\ For 
example, from this Commission's perspective, ancillary services are a 
critical part of a competitive market. However, the ISO's redesign of 
its Ancillary Services markets, which was intended to be a global, 
comprehensive effort to be implemented within perhaps nine to twelve 
months, has been approved and implemented in piecemeal fashion over a 
very long term. Similarly, the ISO's reform of its congestion 
management program has been embroiled in dissension and postponed 
beyond a reasonable length of time.\70\ Most recently, the ISO's 
efforts to address this summer's price abnormalities could not be 
resolved by its Governing Board. The ISO's October 20, 2000 submission 
in this proceeding was not submitted to the Governing Board for its 
consideration. A news report quotes the ISO's President and CEO 
explaining that no consensus regarding market mitigation proposals 
could be developed ``'since everyone had a different concern or a 
different idea for how to change the market.'' \71\
---------------------------------------------------------------------------

    \69\ Staff Report at 6-17.
    \70\ September 12, 2000 Meeting, Transcript at 107, 108 and 127.
    \71\ ``Cal-ISO Asks FERC for Forward-Looking Market Fix,'' The 
Energy Daily, October 23, 2000, p. 2. See also ``Divided Cal ISO 
Postpones Action on Fixes,'' Power Markets Week, Oct. 9, 2000, pp. 
1, 18-19.
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    In addition, over the course of this summer, it has become apparent 
that the Governing Boards are not functioning as they were intended to. 
Members of the ISO Board, in particular, have come under undue pressure 
from various sources, notably regarding votes to change the purchase 
price cap level. One member even felt compelled to resign, and her 
parting words encouraged her colleagues ``to find the determination to 
stand for the principle that the ISO must be independent of 
manipulation by any market participant.'' \72\ Several other members 
also noted pressure ``from people that

[[Page 67050]]

are very powerful.'' \73\ The Staff Report found indications that the 
Boards have been susceptible to influence by market participants, 
particularly by the interest that they represent.\74\ Even California 
authorities have concerns about the Boards' independence. A joint 
Report to the Governor authored by the California Commission and the 
Oversight Board notes that the ISO and PX ``are governed by boards 
whose members can have serious conflicts of interest.'' \75\
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    \72\ Letter of resignation of Camden Collins, dated July 3, 
2000.
    \73\ California ISO Board of Governors Meeting minutes, 28 June 
2000, p. 89.
    \74\ Staff Report at 6-17, 6-18.
    \75\ California's Electricity Options and Challenges: Report to 
the Governor, Executive Summary at 3-4 (Joint Report).
---------------------------------------------------------------------------

    On this record, we have no choice but to conclude that the existing 
California ISO stakeholder board is ineffective and must be modified. 
The ISO is an institution that is central to the functioning of 
wholesale power markets in the West and, unless it is able to resolve 
matters in a timely manner and is independent from market participants, 
we cannot be assured that rates, terms or conditions of its 
jurisdictional services will be just, reasonable and not unduly 
discriminatory or preferential. The transmission assets that the ISO 
operates are a critical part of the interstate transmission grid 
located in the Western Interconnection which provide essential support 
to the electric market. Any failings by the ISO in its obligation to 
ensure reliable operation of the transmission grid would have grave 
consequences for the residents and business in the Western states. 
Operation of this interstate transmission grid must be controlled by an 
expert board which is free from the influence of any market participant 
or market segment.\76\
---------------------------------------------------------------------------

    \76\ As noted in Order No. 2000, which expanded on our Order No. 
888 ISO principles and experience with ISOs, independence is the 
bedrock principle of RTO formation.
---------------------------------------------------------------------------

    We have similar concerns about the independence and effectiveness 
of the PX Board. The PX was created to accommodate California's retail 
access program. However, as discussed in detail below, effective 60 
days from the date of this order, we propose to lift the requirement 
that the IOUs sell into and buy from the PX. Consequently, there is no 
longer any need for a stakeholder body to govern the PX; it may be 
operated as any other power exchange by independent directors.
    While we are proposing to require the removal of the current 
boards, we recognize that the management of both the ISO and PX have 
performed admirably working under extreme circumstances and within the 
system dictated to them both during the initial start-up phase and more 
recently through the extreme conditions of the summer. We also 
recognize their tireless work with the stakeholder boards, a situation 
that was also dictated to them. In order to ensure a successful 
transition, it is vital that continuity of management be maintained.
    We propose in this order that the current stakeholder boards be 
replaced with non-stakeholder boards effective 90 days after the date 
of this order. Under this proposal, in order to accommodate this 
schedule we will require that each new independent non-stakeholder 
board consist of seven voting members with the President (or CEO) as a 
voting member. The six other voting members will be selected by the 
current boards of the ISO and the PX, from a separate slate of 
candidates for each entity prepared by an independent consultant. The 
consultants are to be selected by the CEOs of the ISO and PX. The 
Boards should include members with experience in corporate leadership 
(at the director or board level) or professional expertise in either 
finance, accounting, engineering or utility law and regulation. The PX 
board should include members with expertise in areas of commercial 
markets and trading. The ISO board should include members with 
experience in the operation and planning of transmission systems. To 
allow sufficient time for this transition to occur, we propose to 
require the current ISO and PX Governing Boards to vote in new 
independent, non-stakeholder board members selected from the 
consultant's slate of candidates and disband the existing stakeholder 
boards within 90 days from the date of this order. We emphasize that 
the sole responsibility of the existing boards in the selection process 
is to pick from the slate of qualified candidates identified by the 
independent consultant.
    The ISO and PX have well-established market monitoring units and 
independent surveillance committees that monitor their respective 
markets. This monitoring function focuses on trading activities and 
structural factors. In the October 30, 1997 Order, we accepted the ISO 
and PX proposal allowing market reports to be filed directly to 
regulatory agencies.\77\ While these entities currently have the 
discretion to file their reports directly with the Commission, we 
propose that effective 60 days after the date of this order that all 
ISO and PX market reports be filed by the ISO and PX with the 
Commission at the same time that they are released to their respective 
boards.\78\ This requirement will allow the Commission more timely 
information on market behavior.
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    \77\ 81 FERC at 61,552.
    \78\ This requirement is consistent with the recommendation in 
the Staff Report at 6-18.
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4. Interconnection Procedures
    While siting issues are not within this Commission's jurisdiction, 
we note that tariff interconnection policies are. Further, we note that 
standard procedures to facilitate the interconnection of new generators 
or existing generators seeking to increase the rated capacity of their 
facilities are needed in California. In this regard, we find that the 
ISO tariff lacks any such procedures and we direct the ISO to file 
generation interconnection procedures no later than sixty (60) days 
after the Independent Board is seated. This will ensure that the 
Commission may facilitate the matters under its control in a timely 
manner.

C. Longer-Term Measures

    We believe that current structure in California also requires a 
number of longer-term reforms. While the Commission is not dictating 
any particular revision we propose to direct that the following issues 
be addressed.
1. Reserve Requirement
    Adequate reserves to ensure system reliability is closely related 
to establishing a price that elicits a supply response. Matters of 
planning reserve and reliability are ill-suited to the lag inherent in 
a market response to short supplies. Attracting sufficient supply to 
maintain proper reserve requirements may well benefit from the 
imposition of planning reserve requirements to be met from forward 
markets. Suppliers would be able to build capacity with the financial 
assurance of long-term contracts and would be less tempted to wait 
until spot prices were driven up by low reserve levels. We direct the 
ISO and the Load Serving Entities in California to consider what market 
rules are needed to ensure that sufficient supply is available to meet 
loads and reserve requirements.
2. Alternative Auction Mechanisms
    In times of adequate supply the single price auction disciplines 
prices by encouraging suppliers to bid their marginal costs so that 
they can be selected for dispatch and be paid the clearing price. 
However, in times of scarcity the single price auction can exacerbate 
the effect of supply shortages by allowing sellers who have small 
market shares to set the clearing price.

[[Page 67051]]

Not only is the seller transformed into a price setter rather than a 
price taker, but the resulting price is ascribed to the entire market. 
We are concerned that given the current market in California, the 
single price auction may place little or no discipline on sellers 
during times of shortages by minimizing the risk of strategically 
bidding a small amount of supply for the purpose of raising the price 
of the entire market. It is for these reasons that we propose to 
mitigate prices by eliminating the use of a single price auction at 
prices above $150. While our proposed market reforms will mitigate some 
of the effects of the single price auction, we believe that further 
study of this issue is desirable and direct the PX and the ISO to 
consider, during the 24 month window, whether alternatives to the 
single price auction which minimize the ability of sellers to bid for 
the purpose of setting the clearing price may be appropriate.
3. Balanced Schedules
    We are also concerned that some of the underscheduling problems may 
be a result of the existence of many individual scheduling coordinators 
that are required to submit balanced schedules to the ISO. We therefore 
direct the ISO and the PX to pursue establishing an integrated day 
ahead market in which all demand and supply bids are addressed in one 
venue.
4. Enhanced Market Mitigation
    We direct the ISO and the PX to consider less intrusive, narrowly 
tailored market protection mechanisms. Such mechanisms could take the 
form of the ex ante identification of conditions or behavior that would 
trigger specific market mitigation actions.
5. Congestion Management Redesign
    In California Independent System Operator Corp., 90 FERC para. 
61,006 (2000), the Commission found the ISO's existing congestion 
management structure to be flawed, and, on that basis, we directed the 
ISO to develop and submit to the Commission a comprehensive congestion 
management redesign. Moreover, we stated that such a redesign should be 
pursued with input from all stakeholder groups, as well as from the 
ISO's Market Surveillance Committee. The reform efforts have been the 
subject of extensive public review and comment which are nearing 
completion, and a submission is due to be filed in the near future.
    More recently, in the August 23 Order, we stated that we would 
defer any consideration on the merit of the ISO's congestion management 
structure until the earlier of the ISO's filing of its reform proposal 
or the date which the Commission issues a supplemental order in this 
proceeding. While we consider the ISO's congestion management reform 
efforts to be crucial, we now believe that this particular aspect of 
the California market is not a significant source of this summer's high 
prices and volatility.\79\
---------------------------------------------------------------------------

    \79\ In this regard we note that none of the recent reports or 
analyses of the events of the summer cite to the current congestion 
management structure as contributing to the high prices.
---------------------------------------------------------------------------

    We are however concerned about the delay caused by the existing ISO 
Board on this matter. Therefore we direct the new Independent ISO Board 
to file its redesign proposal no later than sixty (60) days after the 
Independent ISO Board is seated with an implementation date as soon as 
possible. The current congestion management system is fundamentally 
flawed and needs to be overhauled or replaced. This market redesign is 
crucial for providing transmission schedules that are based on physical 
reality and accurate price signals for the siting of new generation. 
Therefore we will require that the proposal, at a minimum, include a 
meaningful number of zones that significantly address congestion on the 
system. In this regard, we also require that the proposal provide a 
comparison with a nodal energy price proposal (i.e. locational marginal 
prices for each bus or node on the grid). We also expect the ISO to 
conduct a periodic (annual) review to evaluate the accuracy of the 
zones for congestion management. We will take any requisite action on 
that proposal at the time it is filed in a separate proceeding.
6. Demand Response Program
    As the Staff Report observed, the difficulty with current demand 
response in California is that it is driven by administrative 
directive, not market prices. (Staff report at 5-21). We direct the ISO 
and Scheduling Coordinators to consider demand bidding programs in 
which loads can bid offers of demand reduction directly into the market 
to compete with offers of supply.
7. Importance of RTO Development and Compliance
    As discussed earlier in this order, California is physically 
integrated into an extensive interstate transmission grid and has 
therefore been part of a western electricity market for a long time. 
California's markets will never realize optimal performance until the 
impediments to efficient utilization of the regional transmission grid 
are eliminated and the regional interstate transmission system is 
designed in such a way that it supports transparent, competitive 
Western bulk power markets---markets that support all of the wholesale 
products that California requires, markets that remove impediments to 
efficient imports and exports, markets that eliminate rate pancaking 
and allow California to access more distant markets at a lower cost, 
markets that undertake regional transmission planning to ensure that 
the needs of California are considered when transmission expansions in 
other states are considered, and markets that allow regional market 
hubs like Palo Verde to develop where new generation can be located to 
serve multi-state markets. The Commission's RTO initiative is a 
response to fundamental changes in the electricity industry over the 
last 20 years. When fully implemented, RTOs will provide for operation 
and planning that will ensure consumer benefits for Californians and 
the citizens of other Western states. The problems being confronted in 
California can, in many ways, be traced to the continued balkanization 
of the Western grid and the absence of a true RTO with regional scope. 
The actions we have taken in this order are fully consistent with Order 
No. 2000, and nothing in this order relieves the ISO, PG&E, SOCal 
Edison or SDG&E from their obligation to make a filing in compliance 
with Order No. 2000 on January 17, 2001. We expect that the matters 
addressed in this order will move the California market toward meeting 
the significant objectives of Order No. 2000 and that these long-term 
market reforms will facilitate California's transformation into a 
properly sized and functioning RTO.

D. Price Mitigation and Refunds

    The Commission has found in this proceeding that the existing 
market structure and market rules, in conjunction with an imbalance of 
supply and demand in California, have caused and, until remedied, will 
continue to have the potential to cause, unjust and unreasonable rates 
for short-term energy during certain time periods. While the Staff 
Report lists a number of factors that legitimately led to higher prices 
last summer,\80\ it also recites

[[Page 67052]]

market design problems that contributed to high prices and that may 
have provided incentives for the exercise of market power or otherwise 
led to higher than competitive prices. \81\ As long as a flawed market 
design remains in effect, the possibility for non-competitive prices 
will continue to exist. Accordingly, pursuant to our statutory 
responsibility under FPA section 206, the Commission not only must 
``fix'' those areas of market design that are within its jurisdiction 
and that are causing the potential for unjust and unreasonable rates 
(i.e., require modifications of existing wholesale market structures 
and market rules that are impeding a competitive price), we must also 
provide measures to assure that rates remain just and reasonable until 
such time as the proposed longer term market remedies can be 
effectuated.
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    \80\ The Staff Report cites, for example, to increases in 
natural gas costs ($2 per MMBtu to $6 per MMBtu January 2000 to 
September 2000); increases in the price of NOX credits 
($5 per pound to over $40 per pound January 200 to September 2000); 
factors contributing to scarcity of power to meet demand such as 
lower than expected hydroelectric output and unplanned power plant 
outages; unusually high temperatures; tight reserve margins; 
increased demand for energy; reduced imports from outside 
California. See Staff Report at pp. 5-2 to 5-7.
    \81\ The Staff Report cites market design problems including 
lack of forward contracting, inadequate demand response; 
underscheduling; and use of a single-price auction to establish 
price. See Staff Report at 5-9 to 5-18. The report shows that design 
problems may have provided incentives for the exercise of market 
power. See Staff Report at 5-9 to 5-26. While findings of specific 
exercises of market power are not in the record, the Staff Report 
refers at p. 5-20 to the analysis of the Market Surveillance 
Committee (MSC) of the ISO, which estimated a significant degree of 
market power being exercised in California markets for the period 
October 1, 1999 to June 30, 2000. The MSC estimated prices for must-
take energy over the entire period were 36.3% higher than they would 
have been under competitive conditions. For the last month of the 
sample, June 2000, they estimated that prices were 64.6% higher than 
they would have been under competitive conditions. The highest 
previous monthly market power index was in June 1998, when prices 
were estimated to be 39.9% higher than they would have been under 
competitive conditions. Average prices in August were higher than in 
June. While costs such as gas and NOX emissions rose, the 
report states that the numbers suggest that market power may have 
been exercised in June. With respect to all of the references in 
this footnote, the standard used to evaluate market power was bids 
above short-run marginal cost.
---------------------------------------------------------------------------

    Below we address two components of protecting ratepayers against 
unjust and unreasonable rates. First, we address price mitigation 
measures that will remain in effect for 24 months, which is the time 
necessary to effectuate all the longer term market structure and market 
rule changes being required. Second, we address the refund liability of 
public utility wholesale sellers in the ISO and PX markets who may have 
the ability to charge unjust and unreasonable rates during certain time 
periods.
1. Price Mitigation Measures
    Between 1996 and 1999 California added about 700 MW of generation 
while its peak load grew by some 5,500 MW fueled by an annual 
population growth of 600,000 people and a robust economy. As a result, 
California's recent peak load and its available installed capacity 
(i.e., in-state capacity not down for maintenance) are effectively 
equal at about 45,000 MW; i.e., there is often barely enough supply to 
meet demand. This leaves California vulnerable to price spikes caused 
by even small suppliers who, under tight supply conditions, can affect 
the PX and ISO market clearing prices. These conditions can allow the 
exercise of market power.\82\ These higher spot market prices in turn 
affect the prices in forward markets. While California has 8,000 MW of 
import capability, WSCC reserves during peak hours in May and June 
dropped to about 5 percent, compared to forecasted planning reserves of 
17-20 percent issued earlier this year, and therefore less energy was 
available for purchase from out of state.\83\ In addition, as virtually 
all reports on this market conclude, there is at present little demand 
responsiveness to price. Accordingly, we propose price mitigation in 
order to allow sufficient time for the implementation of the remedial 
measures we are proposing to order herein as well as the development of 
additional supply and demand response measures. As discussed, infra, 
the price mitigation measures will be in effect for a period of 24 
months.
---------------------------------------------------------------------------

    \82\ Staff Report at 5-19.
    \83\ Price movements in California Electricity Markets, Analysis 
of Price Activity: May-July 2000, California Power Exchange, p. 17 
and 25. Cambridge Energy Research Associates (CERA) has concluded 
that a significant rise in spot prices can be expected when reserve 
margins decline below the 15 to 20 percent range. The Summer 2000 
Spot Electricity Markets Outlook; Divergent Trends in Price 
Volatility, CERA, Lawrence J. Makovich and Joseph Sannicandro, July 
2000.
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    First, we have proposed to free the IOUs of the trade restriction 
of selling all of their generation into and buying all of their supply 
from the PX. This permits the IOUs to avail themselves of the bilateral 
market and forward markets and the ability to self-supply. In so doing, 
the IOUs now have the ability to mitigate their own prices, and 
minimize their exposure in the spot market. Second, requiring 
California market participants to preschedule all resources and loads 
with the ISO coupled with a penalty on all energy transactions of 
greater than 5 percent of the prescheduled amount should greatly reduce 
the amount of supply traded in the real-time market and, thus, will 
shelter Californians from the huge exposure to spot prices experienced 
this summer.
    We propose to implement a temporary modification to the single 
price auctions of the PX and the ISO. A significant factor causing high 
prices in California was the fact that every MW in the market is priced 
at the market clearing price. We propose that, effective 60 days from 
the date of this order, for all short-term markets operated by the PX 
and the ISO (including the Replacement Reserve Market), the single 
price auctions be used for all sale offers at or below $150.\84\ This 
auction modification imposes no limits on a seller's bid and only 
limits which bids can set the clearing price. The single market 
clearing price will be used for the amount of load which clears at or 
below this amount in the auctions. To the extent an auction does not 
clear at or below the $150 bid level, suppliers who choose to bid above 
$150 will be paid their as-bid price.\85\ These prices will be averaged 
and billed to all the load which was supplied in the auction.\86\ 
Allowing generators to receive their as-bid price should permit 
generators whose costs exceed $150 to participate in the market and 
continue to attract new supply by reflecting in prices the true cost of 
scarcity.\87\ This pricing method takes care to mitigate prices by 
reflecting a price to sellers at the margin which signals the supply 
and demand conditions rather than reverting to a traditional cost of 
service basis (i.e., a

[[Page 67053]]

regulated price which reflects the cost of all assets without any 
regard to market conditions). This is crucial in order to induce new 
supply. Bids using this modified single price auction will continue to 
be disciplined by low and moderate cost suppliers bidding their 
marginal costs at times other than shortages to ensure that they are 
chosen for dispatch and can receive the clearing price. At times of 
shortage, we will discipline prices through reporting requirements and 
monitoring as discussed below.
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    \84\ In order to encourage the expansion of Demand Response 
programs, we will not extend this market reform to bids for load 
response.
    \85\ For example, if the highest bid selected in the ISO real-
time market is $75/MWh, this will set the market clearing price and 
all sellers will receive $75. This is the same pricing algorithm 
that is used now. However, if the highest bid selected is $160/MWh 
and the second highest bid selected is $75/MWh, the supplier bidding 
$160 would be paid $160/MWh for the amount it supplied, and the 
market clearing price for all other sellers would be set at $75/MWh. 
In addition, as discussed below, the supplier receiving $160/MWh 
would be required to report that bid to the Commission and provide 
certain cost information to the Commission.
    \86\ This proposed market redesign will also apply to the ISO's 
Replacement Reserve Capacity Market with one modification. In 
certain instances, a supplier may potentially receive both a 
capacity and energy payment. Therefore, the capacity payment for 
replacement reserves will be contingent on whether the supplier is 
called on to produce energy. In that event, the supplier will 
receive only the energy payment.
    \87\ The IOUs have divested most of their fossil generation and, 
as a result, now own mostly hydro and nuclear generation with 
running costs of less than $20/MWh. However, gas is the marginal 
fuel in California and, therefore, we expect to see bids above $150 
under some market conditions. We intend here to monitor these bids, 
not to prohibit them. We also fully appreciate that high cost 
suppliers will bid a margin above their variable costs as a needed 
contribution to their fixed costs. The Staff Report concludes that 
at times of peak demand running costs can be in the range of $160 to 
$200/MWh for some units. Staff Report at 3-21 and 5-3. In addition, 
the PX report (at page 30) on price activity May/July 2000 indicates 
that variable costs during peak periods can approach $500/MWh for 
some units.
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    We propose to require the PX and the ISO to report confidentially 
to the Commission on a monthly basis all bids (both for public 
utilities and non-public utilities) in excess of $150, including the 
name of the seller, the price and amount of MWs covered by the offer, 
the hour(s) covered by the offer, the bid sufficiency in the market 
(i.e., the total amount bid compared to the amount needed), and the 
load at the time of the offer. The ISO also must report unit 
availability data for all Participating Generators. The first report 
must be filed no later than February 15, 2001 for the period January 1, 
2001 through January 31, 2001, and subsequent reports must be filed no 
later than 15 days after the end of each month. This will permit the 
Commission to monitor the effectiveness of the $150 breakpoint and any 
attempted exercise of market power by the market participants.
    In addition, to adequately monitor the competitiveness of markets 
during the 24-month period and ensure just and reasonable rates during 
the time it takes to effectuate the longer term structural and market 
rule remedies, we propose to condition the public utility sellers' 
market-based rate authority by requiring each seller to file on a 
weekly basis each transaction in the ISO and PX spot markets that 
exceeds $150 effective sixty (60) days after this order. We propose to 
require all transactions for the prior week to be filed on a 
confidential basis to the Commission's Division of Energy Markets in a 
single report submitted on the Wednesday following the end of the 
transaction week (ending midnight Sunday). These market data should 
include the name of the seller, the price and amount of MWs covered by 
the transaction, the hour(s) covered by the transaction and the 
incremental generation cost. The filing may also identify legitimate 
opportunity costs that are known and verifiable that the seller 
considered in developing its bid, i.e., prior to the transaction. These 
data will be used to monitor prices on a more current basis, in order 
to detect potential exercises of market power or otherwise non-
competitive market prices and to adjust transaction prices, if 
necessary, to establish just and reasonable rates.
    We recognize that some parties have offered alternative price 
mitigation measures and our decision here is informed by those 
alternative proposals. We believe that a comparison of the major 
attributes of some alternatives that have been proffered shows that the 
option we have selected is appropriate. For example, some parties 
propose that bids into the single price auction be capped at a specific 
level. Recognizing that the single price auction magnifies the impact 
when the maximum bid does not reflect the competitive outcome, by 
paying that same price to all sellers in the market, proponents of 
these measures seek lower and lower ceilings to reduce the economic 
consequences. However, ceilings set too low can also have severe short-
term and long-term consequences on the market. Recognizing these 
concerns, some alternative proposals would include load-differentiated 
price caps that are indexed to estimated load and changes in input 
costs. These proposals, however, introduce significant complexity into 
a market that is already in dire need of simplification. We believe 
that our approach addresses the concerns that underlie these 
alternatives.
    We select $150 as the level above which we will require reporting 
and increased monitoring because this level is indicative of high 
demand. Our review of the bids that cleared in the PX's Day Ahead 
market in August tells us that bids exceeded $150 in about 45% of the 
hours in the month. All these bids were in the peak hours of about 10 
AM to 10 PM. The PX Deficiency Report also shows that during the hours 
of 11 PM to 6 AM prices exceeded $100 nearly 75 times or about 10% of 
the hours of the month and about 30% of the off-peak hours. We intend 
to rely on the single price auction to discipline prices in off-peak 
hours when supply should be adequate.
    We must also take care not to place our breakpoint so high as to 
provide little or no mitigation other than in periods of extreme 
weather conditions such as California faced in August. Our review of 
the bids which cleared in the PX Day Ahead market for September, when 
the heat wave subsided, indicates the use of a higher break point of 
$200 would have reduced price mitigation to 9% of the hours.
    Our selection of the $150 breakpoint is also informed by the 
running costs of the gas-fired generation which is and which we expect 
to be on the margin in California. Selecting a breakpoint which is 
below or barely exceeds the running costs of new entrants is not in the 
interest of consumers. In this critical regard, we have also selected 
$150 because the Staff Report indicates that the running costs alone of 
gas-fired generation often exceeded $100 during the Summer, and our 
review indicates that they have not substantially abated.
    We have also decided not to propose indexing the $150 to gas and 
NOX cost changes in the future. We believe that market entry 
is promoted by simplicity, transparency and stability in pricing rules 
and, therefore, intend to avoid the uncertainty inherent in varying 
this figure. To the extent these costs abate to some degree, we expect 
to see a favorable supply response. There is little sense in increasing 
our reporting requirements at the very time the market is self 
correcting. Conversely, the $150 breakpoint is some $60 above current 
gas and NOX costs for a combined-cycle plant. Accordingly 
suppliers should be able to absorb some rise in gas and NOX 
costs and still have the option of bidding at the $150 level which does 
not trigger reporting and monitoring.
    We also select $150 as a reasonable benchmark for the cost 
consequences of a tight supply. Existing gas fired units \88\ were 
operated at unprecedented levels, driving up the price of 
NOX emission allowances from around $6/lb. to over $40/lb. 
at the end of August.\89\ In addition, gas prices have risen from $2/
MMBtu in the spring to about $5/MMBtu now.\90\ The $150 figure will 
accommodate these marginal running costs for a combined cycle 
generating unit and permits some contribution to fixed costs.\91\ As a 
result, existing suppliers and new entrants whose marginal costs allow 
them to bid within these parameters will not be burdened by reporting 
requirements. This will minimize our intrusion in these markets and 
should attract new suppliers. Those suppliers who cannot accommodate 
their financial needs at or below this

[[Page 67054]]

breakpoint will be paid the as-bid price, but will be required to 
report so that we can monitor their bids.
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    \88\ Natural gas comprises about 55 percent of California's fuel 
mix.
    \89\ Staff Report at 3-21.
    \90\ Average California regional gas prices peaked at about $6/
MMBtu in September and are trending down toward $5/MMBtu. Natural 
Gas Intelligence weekly Gas Price Index, Vol. 13, No. 24. 
NOX costs for the San Diego area have remained above $40/
lb. Cantor Fitzgerald Market Index, October 25, 2000.
    \91\ A combined-cycle generating unit with a heat rate of 10,000 
BTU/KWh will incur fuel costs of $50/MWh, and NOX 
emission costs of $40/MWh. The remaining $60/MWh will permit an 
investment payback of 5 years if the unit is selected for dispatch 
at the $150 level about one-third of the time (i.e. 8 hours per 
day). Selection for one-fourth of the hours would permit a ten year 
payback and selection for one-fifth of the hours would permit thirty 
(30) year payback.
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    Prices based on traditional cost of service are incompatible with 
fostering a competitive market because the cost of the assets will not 
reflect supply or demand conditions. In choosing our price mitigation 
approach, it is our intent to guide these markets to self-correct, not 
to reintroduce command and control price regulation. Monitoring bids 
above the $150 breakpoint will allow the market to respond over the 
next 24 months by ensuring that prices reflect the cost of scarcity 
while allowing us to mitigate potential market power.
    Above we established monthly reporting requirements for the ISO and 
PX and weekly reporting requirements for certain sellers effective upon 
issuance of our final order. We are also concerned about the market 
performance between the refund effective date and when our final order 
becomes effective. Therefore, for this period we propose to establish 
the same reporting requirement on the ISO and PX with respect to bids 
that exceed $150. The ISO and PX reports will be due no later than 
January 30, 2001.
    We expect that standardized electronic filing of these reports 
would facilitate processing of this information and we will finalize 
our guidance on this point in our final order.
2. Refund Liability of Public Utility Sellers in the ISO and PX Markets
a. Refund Liability for the Period October 2, 2000 Through December 31, 
2002
    The Commission has specific authority in section 206 to order 
refunds, if it deems them appropriate, from the refund effective date 
to a period 15 months following the refund effective date. In our 
August 23 order, we noted that refunds were discretionary and that 
refunds may be an inferior remedy from a market perspective and not the 
fundamental solution to any problems occurring in California markets. 
We further stated that while we must protect ratepayers, we do not 
intend to undermine the financial stability of public utility sellers 
and that any decision on whether to impose refund obligations would be 
based on our findings regarding just and reasonable rates and a 
balancing of consumer and investor interests.
    In our August 23 Order, pursuant to section 206 of the FPA, the 
Commission established a refund effective date 60 days from the date of 
our order instituting an investigation on our own motion into the 
practices of the ISO and PX. On September 22, 2000, SoCal Edison and 
PG&E filed for rehearing of this date, seeking a refund effective date 
beginning 60 days after the filing of SDG&E's complaint in Docket No. 
EL00-95-000. The Commission will grant SDG&E's request to establish the 
earliest refund effective date permitted under section 206, which will 
be October 2, 2000.
    We are not now proposing to order any refunds. However, having now 
reviewed the price volatility that has occurred in California and the 
flaws in the market design that can lead to unjust and unreasonable 
rates during certain time periods, we propose that sellers remain 
subject to potential refund liability during the period it takes to 
effectuate the longer term remedies proposed herein. We must be 
vigilant that market manipulation or other anticompetitive behavior 
does not occur and that the combination of market rules and supply 
shortage does not otherwise produce unjust and unreasonable rates while 
the flawed market design remains in effect. Thus, we conclude that not 
only is the market monitoring through increased reporting, discussed 
previously, appropriate, but circumscribed refund liability also is 
appropriate. Therefore, if the Commission finds that the wholesale 
markets in California are unable to produce competitive, just and 
reasonable prices, or that market power or other individual seller 
conduct is exercised to produce an unjust and unreasonable rate, we may 
require refunds for sales made during the refund effective period. 
However, should we find it necessary to order refunds, we will limit 
refund liability to no lower than the seller's marginal costs or 
legitimate and verifiable opportunity costs. This will achieve an 
appropriate balance between ratepayer protection and the seller's 
ability to have an opportunity to recover its costs.
    Finally, because the refund protection under section 206 will end 
15 months following the October 2, 2000 refund effective date, and 
because we cannot be assured that rates will remain just and reasonable 
until longer term remedies are effectuated, we propose to condition the 
market-based rate authorizations of public utility sellers in the ISO 
and PX markets on continuing a refund obligation until such time as the 
longer term remedies are in place (as discussed herein, a period ending 
December 31, 2002). Such potential refund liability, as discussed 
above, would be no lower than the seller's marginal costs or legitimate 
and verifiable opportunity costs.
b. Refund Liability for Period Prior to October 2, 2000
    The Commission has proposed in this order to remedy the structural 
inadequacies of the California bulk power market as quickly and as 
comprehensively as possible. Nevertheless, the most persistent request 
made of the Commission by California officials is to return the 
ratepayers in the SDG&E service territory to the financial 
circumstances they would have experienced this past summer but for the 
series of problems in California's retail, and by implication its 
wholesale, electricity markets. Such equitable relief would take the 
form of a retroactive refund of amounts in excess of just and 
reasonable wholesale rates. During the September 11, 2000 Congressional 
hearing in San Diego, members of Congress stressed the need for relief 
for the citizens of that city. Consequently, the Chairman of the 
Commission, at that hearing, agreed to have staff throughly review the 
state of federal law as it pertains to ordering retroactive refunds of 
wholesale rates.
    The Staff Report, our own San Diego hearing, and all the facts 
collected about this summer's market dysfunctions attest to the 
unanticipated hardship imposed on California ratepayers. The rate 
shocks were severe and unanticipated by consumers. We understand the 
distress of San Diegans, the concerns of their public representatives, 
and the adverse impacts on certain sectors of the local economy, but 
these factors cannot alter the limitations on the Commission's 
authority to change rates that were previously approved, even if 
subsequently found to be unjust and unreasonable. The FPA and the 
weight of court precedent strongly suggest that retroactive refunds are 
impermissible in these circumstances. See Appendix E. The Congress has 
refrained during the 65-year history of the FPA from granting such 
authority in part because of the uncertainty it would create in 
regulated wholesale markets for power. The FPA itself was created, not 
to redress traumatic and inequitable circumstances like this, but to 
provide rate certainty in a relatively static monopoly environment. It 
may be argued that the dynamic power markets of today may warrant 
changes in the Commission's refund authority, at least for extreme 
circumstances, but that does not help the Commission today as it 
considers rate relief to the citizens of San Diego for the summer just 
past.\92\
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    \92\ However, given the new and dynamic environment, the 
Commission is willing to explore any proposal for equitable relief, 
provided that it would ensure that California's electric markets 
remain capable of attracting investment while also mitigating the 
severe financial consequences of last summer's high prices.

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[[Page 67055]]

    The economic distress of high rates is an immediate concern. 
However, the Commission believes that real rate relief for California 
electricity consumers will be fully realized in the State when 
sufficient new generation and transmission resources can be attracted 
and built and better demand-side responses can be prompted. Only 
competitive markets will do these things. We believe it would be a 
mistake to revert to the kind of rate regulation that contributed to 
the decline in investment that clouds California's energy future today. 
On the other hand, the Commission recognizes that market-based rates 
will only achieve just and reasonable rates where competition works 
effectively and market rules are effective and fair. The Commission 
can, and must, focus its efforts in this area.

E. Docket Nos. ER00-3461-000 and ER00-3673-000

    Consistent with the above discussion, we will reject the price cap 
proposed by the PX and the purchase cap amendment filed by the ISO. 
While the ISO purchase price cap has served to mitigate price 
volatility in both the ISO and PX markets, nonetheless it has served to 
disrupt the market by encouraging sellers to stay out of the PX's 
auction and wait for the ISO to make the needed purchases on an out-of-
market basis at the last minute. As we noted in the August 23 
Order,\93\ all the PX and ISO markets are interrelated such that any 
significant modification to one market will affect the other markets. 
Our proposed modification to the single price auctions is intended to 
establish uniform pricing and remove incentives for the load and 
resources to participate in one market over another. For this reason we 
will not allow, at this time, either the PX or ISO to implement changes 
that will disrupt this uniformity or to introduce new incentives in the 
markets. Moreover, we are attempting to provide a period of stability 
in the market in order to encourage supply to enter the market. 
Therefore we will reject the PX and ISO proposals. In the interest of 
maintaining stability in the markets during the transition prior to 
imposing the instant market reforms, we hereby order that the current 
$250 ISO purchase cap remain in place at that level until sixty (60) 
days after the date of this order.\94\
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    \93\ 92 FERC at 61,606.
    \94\ We leave undisturbed the ISO's $100 purchase price cap for 
Replacement Reserves during this time period.
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    We will sunset all price mitigation on December 31, 2002. We 
conclude that 24 months is sufficient to restore order to these 
markets. We discuss below several critical market corrections which 
must be addressed during the 24-month window and we discuss further the 
removal of the auction reform after this 24-month window.

F. Actions Others Should Take

    In well functioning markets which exhibit ease of supply entry and 
demand response to price, consumers react to scarcity by either 
demanding more supply or reducing demand. The current situation in 
California leaves us faced with little supply entry and essentially no 
demand response. The Staff Report documents that this phenomenon 
contributed to high prices in a sellers' market which were not 
sufficiently disciplined by supply and demand responses which consumers 
usually make in setting a scarcity price. It is for this very reason 
that we have adopted a price mitigation which reflects a measure of 
scarcity costs without allowing sellers to systematically set the 
clearing price for the entire market.
    In setting a 24-month window to remedy market problems, we are 
mindful of the fact that the structural defects in the California 
market have been created over many years in an environment which relied 
on regulatory rather than market responses to consumer needs. We have 
intervened not to shelter Californians from the consequences of their 
choices, but to allow a two-year period of transition during which the 
California Commission and other interested parties can make an informed 
decision of whether these are the decisions they wish to make for the 
future in a considered and deliberative environment without the 
distraction of destabilizing price spikes and an increase in overall 
power costs. At the end of our 24-month window, we intend to lift the 
$150 auction modification. At that time, prices will be the product of 
the informed choices Californians have made on supply and demand and 
will reflect the true scarcity cost which they place on electric 
generation.
1. Offering a Full Menu of Forward Products
    As noted, many of the remedies we are proposing are intended to 
move loads into forward markets. Success in this objective is, of 
course, contingent on the availability of supply in forward markets. 
While we understand that the pricing offered for each type of forward 
product may vary to reflect the terms offered (e.g., length of 
contract, risk apportionment, peak vs off-peak), we fully expect that 
California suppliers will welcome the opportunity to offer a full range 
of forward products to meet the needs of their customers. To the extent 
that a full range of forward products (e.g., short-term, intermediate 
term and long-term products) do not become available in California, we 
expect that load-serving entities will bring that to our attention. 
Whether the Commission should require sellers to provide a certain 
percentage of product offerings in the forward market is one issue that 
the Commission will consider in this proceeding.
2. Additions of Generation and Transmission Capacity
    There is little doubt that the most crucial task ahead is to ensure 
that a robust supply enters this market, both now and in response to 
any future price signals. The Staff Report underscores inadequate 
siting of generation and transmission as a key structural defect in 
California. We have made every effort in this order to eliminate market 
design flaws in a manner that promotes efficient markets in order to 
reduce consumers prices to the extent possible given the current 
inadequate supply. However, prompt access to new generation is needed 
to ensure full consumer benefits are realized. For that reason, we have 
also carefully crafted our proposed remedies so as to avoid 
circumstances that may deter new entry, e.g., prices set too low can 
prevent new entry, indecisiveness about the specifics of market reforms 
and price mitigation can deter new entry, and market rules that place 
restrictions on the operation of efficient markets can deter new entry. 
\95\
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    \95\ We note that one of the major costs of scarcity in 
California is the cost of NOX allowances which were 
trading in August for $40/pound or approximately $80,000/ton. By 
comparison, NOX allowances were trading in the Northeast 
for about $400/ton.
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    However, the Commission's authority does not extend to siting, and 
without appropriate siting support, consumers in California will 
continue to pay higher prices due to inadequate generation supply. The 
24-month price mitigation we have ordered herein will afford the state 
and local agencies a window to streamline, facilitate and accelerate 
the siting of needed generation and transmission, including the 
specific projects identified in the Staff Report as furthest along in 
the planning and siting

[[Page 67056]]

process and, therefore, most likely to be completed in the shortest 
time \96\.
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    \96\ See Staff Report at 5-7--5-8, citing California Energy 
Commission's reports on their website which has a listing of the 
proposed generation. The website is www.energy.ca.gov/sitingcases/projects_since_1979.html.
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    Finally, this Commission will commit to expeditiously process any 
energy facility applications (hydroelectric or gas pipeline) within its 
jurisdiction, within the constraints of the law and the need for multi-
agency coordination.
3. Demand Response
    Another matter that lies primarily within the control of state 
policymakers is the development of demand side response. Demand side is 
a critical element of the market. When consumers can receive price 
signals and have the ability to respond to those price signals by 
reducing demand, it reduces the overall cost of electricity in the 
market and reduces the electric bills of all consumers, not just those 
that responded with a load reduction. Also, a viable demand response 
program provides an alternative to resource expansion. The price 
mitigation period proposed in this order provides state policymakers 
with a 24-month window to develop demand response programs, and an 
important opportunity to take measures that can help reduce prices to 
California consumers.
4. Elimination of Impediments to Forward Contracting
    As noted the use of forward products to hedge against spot prices 
is crucial to the development of a well functioning market. We 
encourage the California Commission to eliminate restrictions on the 
IOUs availing themselves of long term products.

Hearing Based on Written Submissions and Oral Presentations to the 
Commission

    In our August 23 Order, we did not determine the type of hearing 
that would be needed in this proceeding. Based on the information 
provided in the Staff Report and the submissions in the record thus 
far, and the nature of the issues presented, we conclude that a trial-
type hearing is not necessary to resolve the matters before us. \97\ 
Further, the need for expeditious resolution of the problems inherent 
in California markets call for as expeditious a hearing as possible, 
consistent with due process and the development of an adequate record. 
Accordingly, the Commission will provide the parties an opportunity to 
file comments, containing all arguments and all supporting evidence 
that they wish to present. All such comments must be filed by November 
22, 2000, which is three weeks from the date of this order. Reply 
comments will not be entertained. In addition, the Commission will 
convene a public conference on November 9, 2000 for interested persons 
to discuss the proposed remedies. A transcript of this conference will 
be placed in the public record of this proceeding.
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    \97\ The use of a ``paper'' hearing rather than a trial-type 
evidentiary hearing has been addressed in several cases. See, e.g., 
Public Service Company of Indiana, 49 FERC para. 61,346 (1989), 
order on reh'g, 50 FERC para. 61,186, opinion issued, Opinion 349, 
51 FERC para. 61,367, order on reh'g, Opinion 349-A, 52 FERC para. 
61,260, clarified, 53 FERC para. 61,131 (1990), dismissed, Northern 
Indiana Public Service Company v. FERC, 954 F.2d 736 (D.C. Cir. 
1992). As the Commission noted in Opinion No. 349, 51 FERC at 
62,218-19 & n.67, while the FPA and the case law require that the 
Commission provide the parties with a meaningful opportunity for a 
hearing, the Commission is required to reach decisions on the basis 
of an oral, trial-type evidentiary record only if the material facts 
in dispute cannot be resolved on the basis of the written record, 
i.e., where the written submissions do not provide an adequate basis 
for resolving disputes about material facts.
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    Based on the record developed in this proceeding, including 
comments and additional information placed in the record in Docket Nos. 
EL00-95-000, EL00-98-000, and EL00-107-000, and the Staff Report, the 
Commission will issue by the end of this calendar year, a final order 
adopting and directing remedies to address the identified problems 
adversely affecting competitive power markets in California, and if 
necessary, ordering any further procedures to develop remedies to other 
identified problems.

The Commission Orders

    (A) The parties may submit to the Commission additional arguments 
and evidence as outlined in the body of this order, by November 22, 
2000. A party's presentation should separately state the facts and 
arguments advanced by the party and include any and all exhibits, 
affidavits, and/or prepared testimony upon which the party relies. The 
statement of facts must include citations to the supporting exhibits, 
affidavits and/or prepared testimony. All materials must be verified 
and subscribed as set forth in 18 CFR 385.2005 (2000).
    (B) The PX's proposed tariff revisions filed in Docket No. ER00-
3461-000 are hereby rejected.
    (C) The ISO's proposed tariff revisions filed in Docket No. ER00-
3673-000 are hereby rejected.
    (D) The ISO is directed to implement a $250 purchase price cap, 
without disturbing the ISO's $100 price cap for replacement reserves, 
for 60 days, commencing on the date of this order, as discussed in the 
body of this order.

    By the Commission. Commissioners Massey and Hebert concurred 
with separate statements attached.
David P. Boergers,
Secretary.

Appendix A--Timely Intervenors in ER00-3461-000

California Department of Water Resources
California Electricity Oversight Board
Duke Energy North America L.L.C., Duke Energy Trading and Marketing, 
L.L.C., and Duke Energy Merchants, L.L.C. (jointly)
Dynegy Power Marketing, Inc.
El Paso Merchant Energy, L.P.
Enron Power Marketing, Inc. and Enron Energy Services, Inc. 
(jointly)
Independent Energy Producers Association
Morgan Stanley Capital Group, Inc.
Pacific Gas and Electric Company
Public Utilities Commission of the State of California
Reliant Energy Power Generation, Inc.
Southern California Edison Company
Southern Energy California, L.L.C., Southern Energy Potrero, L.L.C. 
and Southern Energy Delta, L.L.C. (jointly)
Western Power Trading Forum
Williams Energy Marketing & Trading Company

Appendix B--Timely Intervenors in ER00-3673-000

California Department of Water Resources
California Electricity Oversight Board
California Power Exchange
Cities of Redding, Santa Clara, and Palo Alto, California, and the 
M-S-R Public Power Agency (jointly)
City of San Diego, California
Duke Energy North America L.L.C., Duke Energy Trading and Marketing, 
L.L.C., and Duke Energy Merchants, L.L.C. (jointly)
Dynegy Power Marketing, Inc.
Enron Power Marketing, Inc., and Enron Energy Services, Inc. 
(jointly)
Independent Energy Producers Association
Merrill Lynch Capital Services, Inc.
Metropolitan Water District of Southern California
Modesto Irrigation District
Morgan Stanley Capital Group, Inc.
Northern California Power Agency
Pacific Gas and Electric Company
PPL EnergyPlus, LLC and PPL Montana, LLC (jointly)
Reliant Energy Power Generation, Inc.
Sacramento Municipal Utility District
Southern California Edison Company
Southern Energy California, L.L.C., Southern Energy Delta, L.L.C., 
and Southern Energy Potrero, L.L.C. (jointly)
Transmission Agency of Northern California
Turlock Irrigation District
Western Power Trading Forum
Williams Energy Marketing & Trading Company

Appendix C--Parties to the Consolidated Hearing Proceeding

AES Pacific, Inc.
Arizona Districts

[[Page 67057]]

Automated Power Exchange, Inc.
California Department of Water Resources
California Electricity Oversight Board
California Independent System Operator Corporation
California Large Energy Consumers Association
California Manufacturers and Technology Association
California Power Exchange
Cities of Anaheim, Azusa, Banning, Colton, and Riverside, California 
(jointly)
Cities of Redding, Santa Clara, and Palo Alto, California, and the 
M-S-R Public Power Agency (jointly)
City of Dana Point, California
City of Escondido, California
City of Poway, California
City of San Diego, California
City of Vernon, California
City of Vista, California
Cogeneration Association of California and Energy Producers and 
Users Coalition (jointly)
Duke Energy North America LLC (together with Duke Energy Trading and 
Marketing, LLC and Duke Energy Merchants, LLC)
Dynegy Power Marketing, Inc.; El Segundo Power, LLC; Long Beach 
Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC 
(jointly)
El Paso Merchant Energy, L.P.
Electric Power Supply Association
Enron Power Marketing, Inc., and Enron Energy Services, Inc. 
(jointly)
Independent Energy Producers Association
Merrill Lynch Capital Services, Inc.
Metropolitan Water District of Southern California
Modesto Irrigation District
Morgan Stanley Capital Group, Inc.
New York Mercantile Exchange
Northern California Power Agency
Public Utilities Commission of California (California Commission)
Pacific Gas and Electric Company
Pinnacle West Companies
Portland General Electric Company
PPL EnergyPlus, LLC and PPL Montana, LLC (jointly)
Reliant Energy Power Generation, Inc.
Sacramento Municipal Utility District
Southern California Edison Company
Southern Energy California, L.L.C., Southern Energy Delta, L.L.C., 
and Southern Energy Potrero, L.L.C. (jointly)
The Utility Reform Network
Transmission Agency of Northern California
Western Power Trading Forum
Williams Energy Marketing & Trading Company

Appendix D--Staff Report to the Federal Energy Regulatory Commission on 
Western Markets and the Causes of the Summer 2000 Price Abnormalities; 
Brief Overview of Conclusions (pp. 1-2 to 1-4)

    The report is organized to provide a factual framework for the 
Commission's use, a section discussing major issues evaluated during 
the investigation and, finally, a section with options for 
consideration by the Commission to remedy immediate and longer term 
problems.
    Section 2 of the report finds tight supply and demand conditions 
existed throughout the west during most of this summer, with 
emergency conditions concentrated in California. Broadly speaking,
     Overall demand across the WSCC increased significantly 
driven by hot weather and load increases that were heat sensitive 
and that were also driven by increased economic activity. Average 
summer loads were 11 percent higher in May and 13 percent higher in 
June from the previous year. Energy consumption also increased 
across the WSCC by 5 percent in May and approximately 10 percent in 
June from the previous year. Off-peak demands in the ISO increased 
significantly during the summer, in large part to meet increased 
pumping demands for hydro power facilities, needed for peaking 
purposes both inside and outside of California. However, peak demand 
in the ISO area fell slightly, partially reflecting response to 
emergency declarations and actions.
     Exports increased significantly, with little overall 
change in the level of imports. As a result, net imports decreased 
by approximately 3,000 megawatts (MW) from May through August. The 
ability to increase imports was limited by hydro conditions in the 
Northwest, which actually declined in July and August, and tight 
load conditions in other Western subregions. Weather conditions led 
to increased exports in July and August, corresponding to the 
decreases in the ISO price cap from $750 to $500 in July and then to 
$250 in August.
     Outages increased significantly compared with 1999. 
This was especially true with regard to unplanned outages.
     Increased quantities of demand and supply were left 
unscheduled in day ahead and hour ahead markets. When loads 
increased above 35,000 MW in June and at lower levels in July and 
August, the ISO was forced to buy substantial amounts of power in 
the form of replacement reserves or out of market purchases.
     Non-hydro generation resources throughout the West were 
more heavily utilized in 2000 over 1999. Generation from non-hydro 
resources in 2000 increased by 15.1 percent in May and 24.9 percent 
in July over 1999 levels. Based on a shapshot of WSCC capacity 
during a selected high load period, little additional capacity 
appears to have been available at peak times.
    Section 3 of the report finds that wholesale power prices were 
high throughout the West in the summer of 2000, but their 
implications were most acutely felt in California. The principal 
findings of the report on western prices and costs in the summer of 
2000 are:
     Prices in the ISO spiked in May and June and average 
June prices reached record high levels. While an ISO price cap of 
$750 existed during the early part of the Summer, prices became 
highly volatile and the hourly price hit the cap of 3 days in June. 
Average June prices reached record levels of $120 in the PX.
     Average prices were lower in July and June, but total 
costs paid by purchasers in August were higher than June. Caps of 
$500 in July and $250 in August had a dampening effect on high 
hourly prices, but average prices in August rose to $166 in the PX 
after falling below June levels to $106 in July. The lower caps may 
have played a role in increasing exports in July and August.
     Prices at other trading hubs in the West generally 
correlated with California prices suggesting that opportunities to 
sell at high prices existed in these regions when California prices 
were high. However, it is not yet clear how scarce supplies were in 
these regions or to what extent prices outside California were from 
California imports rather then consumption in other regions. While 
information for certain weeks in the West indicated supply was 
scarce, it was not possible to make an overall assessment on 
scarcity throughout the West without additional information.
     Cost for fuel and environmental compliance 
(NOX credits) increased significantly in July and August. 
Gas prices rose from approximately $2 per MMBtu early in the year to 
approximately $5 per MMBtu in August. Credits to comply with 
NOX standards rose from $6 per pound in May to $35 in 
August and $45 in September. Lower caps in July and August reduced 
the ceiling for market prices while these fuel and environmental 
costs raised the ``floor''. As a result, prices traded over a narrow 
range.
     Prices in some hours appear to be above those that 
would have prevailed in a competitive short-term market, if prices 
were determined from short-term marginal costs.
     Examination of bid patterns in the PX and ISO 
replacement reserve markets and a review of ISO out of market 
purchase activity does not suggest substantial or sustained attempts 
to manipulate prices in these markets. Supply curves bid into the PX 
show higher bids, on average, when the price caps are lower. 
However, the increases are not correlated with particular classes of 
bidders, suggesting that the pattern may reflect increased costs for 
most participants rather than a pattern of individual bidders or 
classes of bidders attempting to raise prices intentionally.
    Section 4 outlines the statutory and regulatory framework 
related to energy markets in the West. The report describes the role 
and policies of the Federal and state economic and environmental 
agencies in regulating electric utilities in California and the 
establishment of the ISO and PX, as well as the creation of the 
Oversight Board. Additionally, this section outlines requirements 
imposed on the California utilities by the California Commission.
    Section 5 discusses the issues that were raised as possibly 
causing the high prices of this summer. These fall into three 
general categories: (a) Competitive market forces, (b) market design 
problems and (c) market power. The data clearly show that a general 
scarcity of power in the West and increased costs to produce power 
were factors causing these high prices. It is also clear that 
existing market rules exacerbated the situation and contributed to 
the high prices. The data also indicate some attempted exercise of 
market power, if the standard of bidding above marginal cost is 
used, and some actual market power effects, to the extent that 
prices, at least in June, were significantly above competitive 
levels. The prices, at least

[[Page 67058]]

in June, were significantly above competitive levels. However, the 
data do not isolate specific exercises of market power or suggest 
that the exercise of market power was more important than other 
primary explanatory factors.
    Section 6 provides a range of options to address the problems 
identified in this report. Staff also attempts in this section to 
provide the possible benefits and drawbacks of various options.
    The investigation was conducted on an expedited basis so there 
was not enough time to address all issues in depth. This report is 
intended to provide the Commission with ``the big picture.''

Appendix E--Analysis of the Commission's Retroactive Refund Authority 
Under the Federal Power Act

I. Executive Summary

    Section 206 of the Federal Power Act authorizes refunds if the 
Commission finds existing rates to be unjust or unreasonable. 
However, that authority is limited to the period from the refund 
effective date through 15 months thereafter. The Commission has the 
discretion to determine that such refunds would not be in the public 
interest in individual circumstances.
    The issue of retroactive refunds was expressly considered by 
Congress in 1935 and again in 1988. In 1935, Congress rejected a 
provision that would have given the Commission authority to order 
refunds for any amounts found to be unreasonable or excessive. 
Instead, the 1935 Act authorized the Commission to change existing 
rates (as distinct from section 205 authority to suspend proposed 
rate increases) prospectively only--i.e., refund relief was 
available only after the Commission found that existing rates were 
unjust or unreasonable. The amendment to section 206 enacted in the 
1988 Regulatory Fairness Act permitted limited retroactive refund 
authority--i.e., from the refund effective date forward.
    Key court precedent interpreting the FPA (and the Natural Gas 
Act, which contains relevant parallel provisions to the FPA) 
articulates the filed rate doctrine and the rule against retroactive 
ratemaking. The filed rate doctrine forbids a regulated entity from 
charging rates for its services other than those properly filed with 
the appropriate regulatory authority. In the area of Federal 
electricity regulation, this doctrine is founded on the requirements 
in section 205 of the FPA that rates for jurisdictional services 
must be just and reasonable and must be on file with the Commission. 
The precedents on the rule against retroactive ratemaking provide 
that, except for certain limited circumstances (e.g., rates 
inconsistent with the filed rate; legal error by the Commission in 
approving rate changes), the Commission does not have authority to 
order retroactive rate changes.
    While there is no Commission or court precedent on the 
applicability of the filed rate and retroactive ratemaking doctrines 
to market-based rates, the provisions of sections 205 and 206 make 
no distinction between cost-based and market-based rates. The refund 
provisions of sections 205 and 206 of the FPA thus would appear to 
apply equally to both cost-based rates and market-based rates. 
Similarly, the filed rate and retroactive ratemaking doctrines, 
which derive from the requirements of sections 205 and 206, would 
appear to apply equally to cost-based and market-based rates.

II. Legal Analysis of Refund Authority

A. Statutory Provisions

    The Commission's statutory authority to order refunds is 
specified in sections 205 and 206 of the FPA. Section 205 addresses 
rate changes proposed by the public utility providing the service in 
question; section 206 addresses rate changes initiated by a 
complainant or the Commission.

1. Section 205

    Section 205(a) provides that all rates and charges made, 
demanded, or received by any public utility for or in connection 
with the transmission or sale of electric energy subject to the 
jurisdiction of the Commission, and all rules and regulations 
affecting or pertaining to such rates or charges shall be just and 
reasonable, and any such rate or charge that is not just and 
reasonable is declared to be unlawful.\98\ Section 205 also requires 
that, absent waiver, a public utility filing any changes in its 
rates, charges, classifications, or services must provide at least 
60 days' prior notice, and permits the Commission to suspend the 
effectiveness of any such change for a period no longer than five 
months. Section 205(e) provides that the Commission ``upon 
completion of the hearing and decision may by further order require 
such public utility or public utilities to refund, with interest, to 
the persons in whose behalf such amounts were paid, such portion of 
such increased rates or charges as by its decision shall be found 
not justified.'' Thus, refunds under section 205 are limited to the 
period beginning with the allowed effective date of the proposed 
rate change and are also limited to the difference between the 
proposed increased rate and the pre-existing rate.
---------------------------------------------------------------------------

    \98\ Section 205(b) provides that: ``No public utility shall, 
with respect to any transmission or sale subject to the jurisdiction 
of the Commission, (1) make or grant any undue preference or 
advantage to any person or subject any person to any undue prejudice 
or disadvantage, or (2) maintain any unreasonable difference in 
rates, charges, service, facilities, or in any other respect, either 
as between localities or as between classes of service.''
    Section 205(c) provides the Commission discretion to prescribe 
rules and regulations, and to establish filing requirements ``within 
such time and in such form as the Commission may designate.''
---------------------------------------------------------------------------

    Section 205 does not, on its face, provide the Commission 
authority to order refunds for periods prior to the effective date 
of the proposed rate change. But, as discussed in Section C.2., 
infra, the Commission may, for example, condition its acceptance of 
a section 205 formula rate filing on the Commission retaining the 
authority under section 206 to, at a later date, retroactively order 
refunds with respect to certain costs charged through the formula.

2. Section 206

    Section 206 provides that if, upon complaint or upon its own 
motion, the Commission finds that existing rates, charges or 
classifications are unjust, unreasonable, or unduly discriminatory 
or preferential, it must determine, and order implementation of, a 
just and reasonable rate. In 1988, in the Regulatory Fairness Act 
(RFA),\99\ Congress substantially revised section 206 to permit 
limited authority to order retroactive refunds of rates found to be 
unjust and unreasonable. Under section 206, as amended by the RFA, 
upon instituting a proceeding under section 206, the Commission must 
establish a refund effective date. In the case of a proceeding 
instituted upon complaint, the refund effective date cannot be 
earlier than the date 60 days after the filing of such complaint nor 
later than 5 months after expiration of such 60-day period. In the 
case of a proceeding instituted upon the Commission's own motion, 
the refund effective date cannot be earlier than the date 60 days 
after publication by the Commission of notice of its intention to 
initiate such proceeding, nor later than 5 months after the 
expiration of such 60-day period. At the end of any such proceeding, 
the Commission may, in its discretion, order refunds if it finds 
that the existing rate is unjust, unreasonable or unduly 
discriminatory or preferential. Possible refunds are limited to the 
period from the refund effective date through a date 15 months after 
such refund effective date and are also limited to the difference 
between the rate charged and the rate determined to be just and 
reasonable.
---------------------------------------------------------------------------

    \99\ 102 Stat. 2299 (1988). The RFA amendments to section 206 
are discussed infra.
---------------------------------------------------------------------------

    On its face, section 206 does not provide the Commission 
authority to establish a refund effective date that is earlier than 
60 days after the date that a complaint is filed or the Commission 
investigates an investigation. Further, section 206 does not contain 
any provision authorizing the Commission to order refunds for 
periods prior to the refund effective date. Therefore, section 206 
does not expressly afford retroactive refund relief for rates 
covering periods prior to the filing of a complaint or the 
initiation of a Commission investigation even if the Commission 
determines that such past rates were unjust and unreasonable.\100\
---------------------------------------------------------------------------

    \100\ As discussed in Section C.2., infra, under the 
Commission's and the courts' interpretations of section 206, there 
are limited circumstances in which the Commission can order refunds 
for past periods.
---------------------------------------------------------------------------

B. The Legislative History of Section 206

    The FPA as originally enacted in 1935 permitted the Commission 
to order refunds in section 206 proceedings prospectively only, 
i.e., prospectively from the date of the Commission's decision. 
While the originally proposed bill that led to the 1935 FPA 
contained a provision which would have allowed the Commission to 
order retroactive reparations, this provision was eliminated from 
the final bill while in committee. Thus, the FPA as enacted in 1935 
allowed the Commission to change unjust or unreasonable rates, upon 
complaint or on its own motion, on a prospective basis only. In 
1988, the Regulatory Fairness Act amended Sec. 206 of the FPA to 
permit specifically limited retroactive refund authority.

[[Page 67059]]

1. The 1935 Act

    The originally proposed bill that led to the 1935 FPA had 
contained a provision (section 213) which would have allowed the 
Commission, upon complaint, to ``order that the public utility make 
due reparation * * * with interest, for amounts charged by an 
electric utility which were thereafter found to be unreasonable or 
excessive.'' S. 1725, 74th Cong., 1st Sess. at 43 (1935).\101\ This 
provision was eliminated from the final bill while in committee, as 
it was considered appropriate for a state utility law, but not 
``applicable to one governing merely wholesale transactions.'' S. 
Rep. No. 621, 74th Cong. 1st Sess. 20 (1935) (emphasis added). Based 
upon the foregoing, it is apparent that Congress drew a distinction 
between retail and wholesale electric rate regulation as to the 
authority required by a regulatory agency to adequately protect 
consumers of electric energy. The reason underlying this distinction 
was not explicitly stated when the legislation was reported out of 
committee. Nonetheless, certain testimony from the hearings held in 
connection with the legislation sheds some light on this subject, as 
set forth below.
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    \101\ Proposed section 213 read as follows: ``Sec. 213. (a) When 
complaint has been made to the Commission concerning any rate or 
charge for any service performed by any public utility, and the 
Commission has found after investigation that the public utility has 
charged an unreasonable, excessive, or discriminatory amount for 
such service in violation of any provision of this title, the 
Commission may order that the public utility make due reparation to 
the complainant thereunder, with interest from the date of 
collection. No such order shall be issued unless the complaint is 
filed with the Commission within two years from the date of the 
payment. (b) If the public utility does not comply with the order 
for the payment or reparation within the time specified within such 
order, action may be begun in any court of competent jurisdiction to 
recover the same within one year from the date of the order, and not 
thereafter.''
---------------------------------------------------------------------------

    John E. Benton, General Solicitor of the National Association of 
Railroad and Utility Commissioners (NARUC) appeared before the House 
committee on behalf of his organization and argued for the 
elimination of section 213. Public Utility Holding Companies; 
Hearings on H.R. 5423 Before the House Comm. on Interstate and 
Foreign Commerce, 74th Cong. 1st Sess. 1684-1685 (1935) [hereinafter 
cited as House Hearings]. Mr. Benton stated:
    The next amendment, we ask that section 213, beginning on page 
118, be stricken out.
    That is the reparation provision brought in from the Interstate 
Commerce Act. It provides that if service taken has been charged for 
at an unreasonable or excessive rate, and if within 2 years an 
application is made to the Commission, it may disapprove the rate 
charged and fix a reasonable rate, and require the selling utility 
to make due reparation to the complainant.
    That is an entirely proper provision in a railroad statute. When 
a man goes to the railroad station with a load of goods to ship 
somewhere he has to ship at the rate that is fixed in the tariff. He 
must make the shipment then; and he ought to be able to come 
thereafter to the Commission and show that he was required to pay an 
unreasonable rate, if it was unreasonable, and to ask for a 
determination of a reasonable rate and get reparation that is due 
him for any overpayment. That is perfectly proper. But this bill 
relates only to service between the wholesale generating or 
production company and the distributing utility. We question whether 
the public interest will be served by giving any company the right 
to go ahead receiving service at the established rate for 2 years, 
and then to bring a complaint before the Federal Commission that the 
rate has been unreasonable. If the provision were that the 
reparation might run after the complaint was made, it would be more 
reasonable. But to allow the company to take service for 2 years 
with no question raised and then to allow it to come in and file a 
complaint, we believe, is not reasonable. We ask that the provision 
be stricken out or that it be limited to a recovery of reparation 
after the complaint is filed.
    Id. 
    Whether the distinction drawn by Congress between wholesale and 
retail rate regulation was based on the relative volume of wholesale 
and retail sales existing at the time is unclear. Commissioner Clyde 
L. Seavey of the Federal Power Commission testified in support of 
the bill and discussed generally the need for Federal regulation of 
wholesale rates. House Hearing, supra, at 420-25. Commissioner 
Seavey testified that more than 17 percent of the total electric 
energy generated at that time was transmitted interstate, and that 
of this 17 percent, ``practically all of it is wholesale in 
nature.'' Id. at 420-21.
    Now, in the electric energy field, at the present time the 
movement of interstate transmission is over 17 percent. That, 
however, in percentage does not in either case indicate the full 
measurement of the need of regulation. A larger or a smaller 
percentage does not spell very much and that is not advanced at this 
time by the Commission as urging that regulation is more than it is 
in the smaller percentage, but it is interesting to note, I think, 
that there is a very substantial movement of interstate energy at 
the present time.

Id. at 420 (emphasis added).
    Based upon the foregoing, it appears that section 213 was 
included in the proposed legislation submitted to Congress by the 
Federal Power Commission as a standard utility law provision 
borrowed from the Interstate Commerce Act. It further appears that 
Congress accepted the argument set forth by the General Solicitor of 
NARUC that wholesale customers of electric utilities should not be 
permitted to accept service for up to two years without complaint 
and thereafter be permitted reparations covering that period. 
However, Congress did not explicitly accept the General Solicitor's 
alternative suggestion that the time period for recovery of 
reparations should commence with the filing of the complaint, and 
instead eliminated section 213 entirely. As discussed infra, this 
resulted in the courts later concluding that Congress intended that 
the Commission have authority to only grant relief in a section 206 
proceeding prospectively from the date of its order,\102\ and it 
also led to Congress providing limited retroactive refund authority 
in the RFA of 1988.
---------------------------------------------------------------------------

    \102\ See, e.g., City of Bethany v. FERC, 727 F.2d 1131 (D.C. 
Cir. 1984), cert.denied, 469 U.S. 917 (1984).
---------------------------------------------------------------------------

2. The Regulatory Fairness Act of 1988

    The Senate Report on the RFA \103\ contrasted the Commission's 
refund authority under sections 205 and 206. It noted that section 
205 proceedings on average required one year for resolution and that 
final decisions by the Commission are retroactive to the effective 
date of the rate increase. With respect to section 206, the Senate 
Report stated:
---------------------------------------------------------------------------

    \103\ The House passed H.R. 2858, a Senate Committee amended the 
House-passed bill, and the Senate passed H.R. 2858, as amended.
---------------------------------------------------------------------------

    Section 206 of the FPA allows the Commission, on its own motion 
or pursuant to complaint, to set a ``just and reasonable rate'' if 
it finds the rate in effect to be unlawful. Under existing law, a 
rate reduction under section 206 differs from a rate increase under 
section 205 in two important ways. First, a motion or complaint for 
rate reduction does not take effect automatically after a given 
period of time as does a request for rate increase. Second, under 
section 206 a rate reduction is prospective only.
    Resolution of section 206 proceedings requires two years on 
average. One probable reason for the longer period needed to resolve 
such proceedings is that public utilities have no incentive to 
settle meritorious section 206 complaints since any relief is 
prospective. Under present law, public utilities keep revenues 
collected during the pendency of a section 206 proceeding, even if 
those revenues are subsequently determined to be excessive. H.R. 
2858 would correct this problem by giving FERC the authority to 
order refunds, subject to certain limitations.\104\
---------------------------------------------------------------------------

    \104\ S. Rep. No. 491, 100th Cong., 2d Sess. 3-4 (1988), 
reprinted in 1988 U.S.C.C.A.N. 2685.
---------------------------------------------------------------------------

    Thus, the RFA was intended to correct the problem of public 
utilities engaging in dilatory behavior in section 206 proceedings 
in order to delay the effectiveness of proposed, presumably lower, 
rates. The RFA did so by giving the Commission the authority to 
establish a refund effective date and make an existing rate subject 
to refund during the pendency of a section 206 proceeding for a 
period of up to 15 months from the refund effective date (longer if 
the public utility is found to have engaged in dilatory behavior 
during the hearing).
    The Senate Report also explains that the burden of proof was 
unchanged by the RFA, i.e., the Commission or a complainant has the 
burden of proof to show that an existing rate, charge or related 
provision is unlawful and that the proposed rate is just and 
reasonable.\105\
---------------------------------------------------------------------------

    \105\ S. Rep. No. 491 at 5, reprinted in 1988 U.S.C.C.A.N. 2687.
---------------------------------------------------------------------------

    The Senate Report also states that the RFA was intended to give 
the Commission the discretion needed to deal with individual 
circumstances in which refunds would not be in the public interest:

[[Page 67060]]

    As passed by the House of Representatives, H.R. 2858 required 
refunds to be paid subject only to a narrowly drawn public interest 
exception. The Committee amended the House-passed bill to make the 
granting of refunds under section 206 discretionary so as to 
parallel the refund provision of section 205 of the Federal Power 
Act. The Committee recognizes that it may not be appropriate in all 
instances to order refunds in the event that it is determined in a 
proceeding under section 206 of the Act that rates or charges are 
not just and reasonable.
    The Committee intends the Commission to exercise its refund 
authority under section 206 in a manner that furthers the long-term 
objective of achieving the lowest cost for consumers consistent with 
the maintenance of safe and reliable service.
    The Committee is aware that there may be challenges to power 
pooling and system integration agreements brought under section 206 
of the Federal Power Act in which refunds might not be appropriate, 
for example, where the issue relates to cost allocation among 
utilities, and the bill as reported by the Committee is intended to 
provide the Commission with the discretion needed to deal with 
individual instances in which refunds would not be in the public 
interest.
    In determining if a refund may adversely affect the public 
interest in the case of power pool agreements, the Committee expects 
the Commission to consider whether, and the extent to which, a 
refund would adversely affect decisions made on the basis of energy 
pricing provisions of such pooling agreements or will impose a 
substantial burden on the pool in comparison with the benefits of 
refunds to consumers.
    In addition to certain situations involving power pooling, there 
may be others in which the public interest would not be served by 
requiring refunds under section 206. Because the potential range of 
these situations cannot be fully anticipated, no attempt has been 
made to enumerate them here. In any case, the Committee generally 
expects the Commission to grant refunds under section 206 with 
comparable frequency to its granting of refunds under section 
205.\106\
---------------------------------------------------------------------------

    \106\ S. Rep. No. 491 at 5-6, reprinted in 1988 U.S.C.C.A.N. 
2687-88.
---------------------------------------------------------------------------

    Thus, the Commission is given the discretion to determine 
whether, for example, a public utility's financial viability and 
ability to serve customers might be jeopardized if very large 
refunds were ordered.

C. Court Precedent

    Two court doctrines have arisen from the courts' interpretations 
of the limitations of sections 205 and 206 of the FPA: the filed 
rate doctrine and its corollary, the rule against retroactive 
ratemaking.

1. Key Court Precedent Involving the Filed Rate Doctrine Under the FPA 
and Natural Gas Act

    The filed rate doctrine ``forbids a regulated entity [from] 
charg[ing] rates for its services other than those properly filed 
with the appropriate regulatory authority.'' Arkansas Louisiana Gas 
Co. v. Hall, 453 U.S. 571, 577 (1981). In the area of federal 
electricity regulation, this doctrine is founded on the requirements 
in section 205 of the FPA that rates for jurisdictional services 
must be just and reasonable and must be on file with the Commission. 
The considerations underlying the rule are ``preservation of the 
agency's primary jurisdiction over reasonableness of rates and the 
need to insure that regulated companies charge only those rates of 
which the agency has been made cognizant.'' City of Cleveland v. 
FPC, 525 F.2d 845, 854 (D.C. Cir. 1976); see also Montana-Dakota 
Utilities Co. v. Northwestern Public Service Co., 341 U.S. 246, 251-
52 (1951).
    In cases involving the Commission, the D.C. Circuit has 
explained that--
    [v]arious reasons have been offered in support of the filed rate 
doctrine, and its corollary prohibiting the regulatory agency from 
altering a rate retroactively. Most recently, the Court justified 
the doctrine as necessary to enforcement of the underlying statute 
(Maislin, 110 S. Ct. at 2769), in that case the Interstate Commerce 
Act. The Court has also described the considerations underlying the 
doctrine as `` `preservation of the agency's primary jurisdiction 
over reasonableness of rates and the need to insure that regulated 
companies charge only those rates of which the agency has been made 
cognizant.'' ' Opinions of this court have cited ``necessary 
predictability'' as ``the whole purpose of the well-established 
`filed rate' doctrine * * * . '' In the context of the Interstate 
Commerce Act, the Supreme Court has indicated that the doctrine 
fulfills ``the paramount purpose of Congress'' of preventing 
``unjust discrimination.'' Other courts of appeals have described 
the doctrine as intending ``to prevent discriminatory rate 
payments'' and as ``reflecting a statutory bias in favor of 
retroactive rate reductions but not retroactive rate increases.''
    Whatever the justification, it is generally agreed that with 
respect to the Federal Power Act, the filed rate doctrine rests on 
two provisions: section 205(c), which requires utilities to file 
rate schedules with the Commission, and section 206(a), which allows 
the Commission to fix rates and charges, but only prospectively 
[emphasis added].\107\
---------------------------------------------------------------------------

    \107\ Towns of Concord, Norwood and Wellesley v. FERC, 955 F.2d 
67, 71-72 (D.C. Cir. 1992) (citations and footnotes omitted) (Towns 
of Concord v. FERC). See also Natural Gas Clearinghouse v. FERC, 965 
F.2d 1066, 1075 (D.C. Cir. 1992).
---------------------------------------------------------------------------

    The DC. Circuit further explained that as the filed rate 
doctrine and rule against retroactive ratemaking ``relate to 
purchasers, their guiding concern is `[p]roviding the necessary 
predictability,' allowing `purchasers of gas to know in advance the 
consequences of the purchasing decisions they make.' ''\108\
---------------------------------------------------------------------------

    \108\ Towns of Concord v. FERC, 955 F.2d at 75. See also Texas 
Eastern Transmission Corp. v. FERC, 102 F.3d 174, 188-89 (D.C. Cir. 
1996) (filed rate doctrine ``seeks to prevent customers from relying 
on certain rates, only to find later that their purchasing decisions 
have been upset and their costs increased.'') Public Utilities 
Comm'n of California v. FERC, 988 F.2d 154, 164 (D.C. Cir. 1993) 
(``when determining whether a FERC order violates either the filed 
rate doctrine or the rule against retroactive ratemaking, this court 
inquiries whether as a practical matter, the purchasers of the 
[energy] had sufficient notice that the approved rate was subject to 
change.'').
---------------------------------------------------------------------------

2. Key Court Precedent Involving the Rule Against Retroactive 
Ratemaking Under the FPA

    Except for certain limited circumstances discussed below 
(formula rates, legal error by the Commission), the courts have 
consistently held that under the FPA, the Commission does not have 
authority to order retroactive rate decreases. See FPC v. Sierra 
Pacific Power Co., 350 U.S. 348, 353 (1956); Public Service Co. of 
New Hampshire v. FERC, 600 F.2d 944, 957 n.51 (D.C. Cir. 1979), 
cert. denied, 444 U.S. 990 (1979).
    In a United States Supreme Court opinion addressing the Federal 
Power Commission's lack of authority to order reparations under 
section 205(a), the dissent (which concurred with the court's 
conclusion that the FPA does not authorize reparations under section 
205(a)) stated:
    We face at the outset the contention that this section confers 
on the Federal Power Commission authority to award reparations for 
unreasonable rates collected in the past. Federal railroad rate 
legislation gave such a power to the Interstate Commerce Commission. 
(citations omitted). But it was not given to the Federal Power 
Commission. It was withheld deliberately. See S. Rep. No. 621, 74th 
Cong., 1st Sess. 20. Wholesale consumers of electric energy were 
apparently considered, as a rule, adequately protected by the 
provisions of the Act authorizing the Commission to grant 
prospective relief and, in certain circumstances, to order refunding 
of sums accumulated during the pendency of rate proceedings. 
Secs. 205(e), 206(a), 49 Stat. 852, 16 U.S.C. Secs. 824d(e), 
824e(a).

Montana-Dakota Utilities Co. v. Northwestern Public Services Co., 
341 U.S. 246 at 257-58 (1951), (Frankfurter J., dissenting on other 
grounds).
    As the D.C. Circuit in City of Piqua stated:
    In essence, the rule against retroactivity is a ``cardinal 
principle of ratemaking[:] a utility may not set rates to recoup 
past losses, nor may the Commission prescribe rates on that 
principle.'' [citation omitted] * * * The retroactive ratemaking 
rule thus bars utility refunds for past excessive rates, or the 
Commission's retroactive substitution of an unreasonably high or low 
rate with a just and reasonable rate.

City of Piqua v. FERC, 610 F.2d 950, 954 (D.C. Cir. 1979).
    There are, however, some limited circumstances under which the 
Commission can order refunds for past periods. For example, where 
the Commission has conditionally accepted for filing a formula rate 
(such acceptance is subject to the condition that the Commission 
may, at a later date, retroactively order refunds with respect to 
certain costs impermissibly charged through the formula) and the 
utility has charged impermissible costs through the formula, or 
where the rates charged were contrary to the filed rate, the 
Commission may order refunds. See, e.g., Appalachian Power Co., 23 
FERC para. 61,032 at 61,088 (1987). The Commission may also be able 
to order refunds as a remedy to correct legal

[[Page 67061]]

errors found by an appellate court upon judicial review of a 
Commission order on a requested rate change. United Gas v. Callery 
Properties, 382 U.S. 223, 229 (1965) (while the Commission has no 
power to make reparation orders, its power to fix rates being 
prospective only, it is not so restricted where its order, which 
never became final, has been overturned by a reviewing court); 
Reynolds Metals Co. v. FERC, 777 F.2d 760, 763 (D.C. Cir. 1985); see 
Public Utilities Commission of the State of California v. FERC, et 
al., 988 F.2d 154, 161-162 (1993) (allowing pipeline to seek 
retroactive recovery of costs based on court reversal of FERC order, 
citing ``general principle of agency authority to implement judicial 
reversal''). In Office of Consumers Counsel v. FERC, 826 F.2d 1136 
(D.C. Cir. 1987), the court held that where the Commission had 
committed legal error in failing to order rate relief to 
consumers,\109\ rate relief dating back to the date of the 
Commission's error would not violate section 5 of the NGA \110\ 
since this would place consumers in the same position they would 
have occupied had the error not been made.\111\ See also Tennessee 
Valley Mun. Gas Assn. v. FPC, 470 F.2d 446, 453 (D.C. Cir. 1972) 
(granting of refunds did not violate anti-reparations language in 
the statute which was designed to protect established expectations 
under legally established rate schedules; one ``cannot claim 
justifiable reliance or protectable expectations based on 
[Commission] action which was illegal'').
---------------------------------------------------------------------------

    \109\ The court determined that the Commission had committed 
legal error.
    \110\ 15 U.S.C. Sec. 717d (1994). Section 5 of the Natural Gas 
Act is analogous to section 206 of the FPA.
    \111\ In Exxon Co., U.S.A. v. FERC, 182 F.3d 30, 49 (D.C. Cir. 
1999), the court held:
    The goals of equity and unpredictability are not undermined when 
the Commission warns all parties involved that a change in rates is 
only tentative and might be disallowed.* * *  As we stated in 
[Public Service Co. of Colorado v. FERC, 91 F.3d 1478 (D.C. Cir. 
1996)], ``[a]bsent detrimental and reasonable reliance, anything 
short of full retroactivity * * * allows [some parties] to keep some 
unlawful overcharges without any justification at all.'' 91 F.3d at 
1490.
---------------------------------------------------------------------------

D. Applicability of the Refund Provisions of Sections 205 and 206 
and the Filed Rate and Retroactive Ratemaking Doctrines to Market-
Based Rates

    No distinction between cost-based and market-based rates is made 
in the FPA. Indeed, the statute itself does not dictate or even 
indicate how the Commission is to establish rates. Nor have courts 
found the Commission to be ``bound to the use of any single formula 
or combination of formulae in determining rates.'' FPC v. Hope Gas 
Co., 320 U.S. 591, 602 (1944); see Duquesne Light Co. v. Barasch, 
488 U.S. 299, 310 (1988) (same). Section 205(c) of the FPA is clear, 
however, that all rates and charges for jurisdictional transactions 
must be on file with the Commission. Further, a Commission-approved 
rate, whether cost-based or market-based, may not be changed, except 
as provided by sections 205 and 206 of the FPA. The refund 
provisions of sections 205 and 206 of the FPA thus would appear to 
apply equally to both cost-based rates and market-based rates. 
Similarly, the filed rate and retroactive ratemaking doctrines, 
which derive from the requirements of sections 205 and 206, would 
appear to apply equally to cost-based and market-based rates. There 
is no court or Commission precedent that addresses the question 
directly, however.

Massey, Commissioner, concurring:
    Today the Commission takes a step toward restoring confidence 
that wholesale markets in California can produce just and reasonable 
prices and consumer benefits. I am concurring on this proposed 
order, and want to make a number of points.
    First, our order finds that the California wholesale market has 
produced wholesale prices for electricity that are unjust and 
unreasonable, and that remedies are necessary. On August 23d, in 
voting on the complaint filed by San Diego Gas & Electric, I reached 
this conclusion and set forth my opinion in a separate written 
statement. Although I have maintained an open mind on all issues 
during the course of our subsequent investigation, I am convinced 
that any reasonable interpretation of the record now before us today 
leads to this same conclusion.
    Second, our order moves in the right direction toward remedying 
the problems in California's electricity market. It correctly 
identifies the problems that must be addressed going forward to 
ensure just and reasonable rates and protect consumers. The over 
reliance on spot markets, underscheduling leading to high prices in 
the real time markets, and the lack of a demand response are clearly 
areas that must be dealt with effectively, and our order proposes 
remedies in each of these areas. I am pleased that our order 
requires the ISO and PX to reconstitute their governing boards with 
independent members and abolishes the so-called stakeholder boards. 
Today's order eliminates the state-imposed requirement that the 
three California utilities sell into and buy from the PX, and I 
support the ending of this so-called buy/sell requirement.
    Third, our order proposes price mitigation going forward. No bid 
in excess of $150/MWh will set the market clearing price in the ISO 
and PX auctions. Sellers may bid above this level and receive their 
bid if they are dispatched, but they will not set the price that all 
generators will receive and must report their bid to the Commission.
    And fourth, from October 2, 2000 going forward, purchasers may 
be entitled to refunds for any unjust and unreasonable wholesale 
prices that may be charged over the following 24 months.
    In some of these areas, however, I continue to advocate a more 
aggressive approach. One of these is forward contracting. Our order 
finds that there has been an over reliance on spot markets in 
California, and that consumers have suffered from this. We rightly 
focus attention on the importance of forward contracts as a way for 
both buyers and sellers of power to hedge the risk of volatility in 
the ISO and PX spot markets, and we encourage state policymakers to 
remove unnecessary barriers to forward contracting. Our order says 
that we expect public utility sellers to offer a full range of 
forward contracts covering both short and long-term periods of time. 
I agree with these conclusions, but would like comment from parties 
to this proceeding on whether the Commission's final order should 
take additional steps to ``kick start'' the market for forward 
contracting.
    Should we, for example, require sellers during the two-year 
mitigation window to forward contract with California load serving 
entities a certain percentage of their supply? In a recent pleading 
styled an Offer of Settlement, the California ISO suggests a forward 
contracting requirement of 70%. Should the Commission require a 
certain amount of forward contracting as a temporary measure to 
mitigate market power in spot markets? Should such an obligation be 
placed on sellers or buyers, or both? Should the Commission specify 
a certain level, or does this unnecessarily intrude into business 
arrangements? During our recent hearing in San Diego, Professor 
Frank Wolak, Chairman of the ISO's Market Surveillance Committee, 
suggested that the Commission define a forward contract of 18-24 
months duration, set a just and reasonable price for such a 
contract, and attempt to reach agreement with the California PUC 
that purchasing such a contract would be deemed prudent. I would 
appreciate comments on the viability of this concept as well.
    Another issue on which I would like comment from parties is our 
order's proposed $150/MWh ceiling on the market clearing price. Is 
this a sufficient consumer protection measure? This ceiling would 
last for 24 months. Our order concludes that in some hours, and 
particularly at high load levels when there is an imbalance between 
supply and demand, flawed market rules and a flawed market structure 
allow the exercise of market power that must be effectively 
mitigated. Under the proposed $150 ceiling, a generator that bids 
higher and is dispatched can receive the higher bid, so this is not 
a hard $150 cap, but this higher bid will not set the market 
clearing price, and the generator must file a report to allow the 
Commission to evaluate the bid. This $150 ``soft cap'' is designed 
to accommodate the marginal running costs for a combined cycle 
generating unit, dispatched roughly one third of the time, with an 
investment payback period of 5 years. It seems to me that these same 
assumptions, coupled instead with a 10 year payback period, might 
justify a $120 ceiling. Or the price of natural gas could fall, 
justifying a somewhat lower ceiling.
    I would like comment on whether this soft cap is a good idea. 
Will it be an effective market power mitigation measure? Has the 
Commission balanced competing interests reasonably in choosing the 
$150 level? Should such a cap vary at different load levels or with 
the price of natural gas or NoX credits? Commenters 
should keep in mind that today's order proposes to eliminate the 
ISO's purchase price cap authority, which is the only wholesale 
price mitigation protection customers have had, so the $150 soft cap 
should be evaluated with this in mind. Would a 24 month hard cap be 
more appropriate or would it deter entry of much-needed generation.

[[Page 67062]]

    Our order deals with other important issues. With respect to the 
issue of retroactive refunds for last summer when prices were very 
high, our Office of General Counsel has prepared a legal memorandum 
that concludes that the Commission has no authority to order refunds 
for any period of time before October 2, 2000. I realize that this 
is an issue of utmost importance to the residents of California. 
This agency must act within the authority delegated by law, and the 
Congress has not given us this authority, according to our legal 
staff. Today's order concludes, however, that the Commission would 
consider any equitable remedies that parties wish to propose in this 
area. I interpret this language among other things to invite comment 
on the extent of the Commission's authority in the area of refunds. 
Has our legal staff reached the correct conclusion? Are there legal 
precedents or arguments that we have overlooked or misconstrued? 
This is such an important issue that we should use the comment 
period to ensure that we reach the correct conclusion with respect 
to the scope of our refund authority.
    Finally, our order attempts to lay out the areas of concern that 
we believe are our responsibility under the Federal Power Act, 
including the justness and reasonableness of wholesale prices and 
ensuring the independent management of the transmission grid. But 
for the wholesale market to function well, California needs new 
generation and transmission capacity, and the siting of new 
facilities is clearly within the jurisdiction of the State of 
California. I know that I am stating the obvious, but I just want to 
make the point that we share jurisdiction over electricity 
regulation with the State of California. We must do our part, and 
the state must do its part to ensure that customers benefit from 
competition. I look forward to working with the State of California 
to ensure that consumers do in fact benefit from competitive markets 
that produce just and reasonable prices. That is what today's order 
is all about.
    In conclusion, this is not a perfect order. I seek comment on 
whether we should take a more aggressive approach to certain issues. 
Going forward, this Commission must take each and every measure 
necessary to protect consumers from unjust and unreasonable prices. 
We must ensure that consumers benefit.

William L. Massey,
Commissioner.
Hebert, Commissioner, concurring:

Introduction

    As much as I would like to offer a recitation that would be more to 
the liking of San Diegans, and sit as the most popular member of this 
Commission, my oath, taken almost exactly three years ago on this date, 
requires me to regulate in a forthright and intellectually honest 
fashion. We must provide supply and deliverability opportunities in 
America and, especially, in California. Worse than high prices, 
reliability concerns for the good people of California must be a 
priority.
    Recent events demonstrate two things. California wholesale 
electricity markets require reform. And California ratepayers deserve 
relief.
    In today's order, the Commission attempts to accomplish both tasks. 
Frankly, in my judgment, it is not altogether clear whether the 
Commission has moved in the direction of achieving its stated goals of 
reforming California markets and helping California ratepayers. If it 
were up to me, today's order would be much, much different.
    Nevertheless, on balance, today's order appears to be a step in the 
right direction. For this reason, I hesitantly concur. However, there 
remains much uncertainty as to the practical effect of various remedial 
measures adopted in today's order. I can support the order only because 
it does not represent the last word; it is merely a ``proposed'' order. 
A technical conference and a round of comments from the public will 
follow. If, after listening to comment on the subject, I am convinced 
that the Commission has moved in the wrong direction--and I am 
perilously close to that conviction right now--I will not be hesitant 
to upset the basket of remedial measures adopted today.
    I write separately to present for comment the basket of remedial 
measures I would adopt, if given the chance. I agree with today's order 
to the extent it explains that California electricity markets suffer 
from serious structural defects that inhibit the operation of a 
competitive market. I also agree that the current situation requires 
``decisive'' action; otherwise, California markets will not move toward 
the goal we all agree on. The Commission needs to act now to ensure 
that energy suppliers have an incentive to enter capacity-starved 
California markets, that local utilities have strong reason to hedge 
against price risk, that entrepreneurs have a motivation to develop new 
products and technologies, and that consumers share a motivation to 
conserve.
    I simply disagree with today's order with respect to its selection 
of corrective measures. Some will help; others will hurt. Others not 
selected would have helped more. The Commission should have stopped 
with corrective measures designed to remove impediments from the 
operation of a competitive market. Instead, unfortunately, it decided 
to go farther and adopted additional measures that prescribe with 
tremendous specificity how market institutions and market participants 
should act during the transition period to a fully competitive market. 
The majority of the Commission believes that various prescriptive 
measures will ease the pain felt by market participants during what it 
believes will be a two-year transitional period.
    I believe, however, that the Commission's overreaching will only 
prolong the transition period for an indefinite period. If the 
Commission were truly committed to the competitive ideals articulated 
in today's order, it would have taken ``decisive'' action to ensure 
that California markets achieve those ideals as quickly as possible. 
Now is not the time for timidity. California ratepayers will benefit 
from the restructuring of the California energy market only when that 
market is allowed to operate without artificial restraints designed by 
regulators who believe that they know best how to serve energy 
customers.
    I now proceed to explain the basket of remedial measures I would 
adopt to address the California electricity situation. I then explain 
those measures adopted by the Commission that I would not have adopted. 
I finish with a discussion of the Commission's attitude toward refunds.

Remedial Measures I Would Adopt

1. Eliminate All Price Controls

    Today's order is filled with repeated references to the perceived 
need for ``price mitigation.'' As a general matter, I find the concept 
of ``price mitigation'' to be an offensive one. Government should not 
be mitigating prices. It is ill-equipped to do so; its efforts 
invariably back-fire to the detriment of consumers. Rather, market 
participants--primarily energy suppliers and energy consumers--should 
be entrusted with the ability and the responsibility to mitigate their 
price exposure as they deem best.
    This is a subject that I have written about in numerous dissents 
and concurrences over the past three years. Events in California 
demonstrate that my position is not merely academic or philosophical. 
In a report dated September 6, 2000, the Market Surveillance Committee 
of the California ISO concluded that price caps have little ability to 
constrain prices. Specifically, it noted that monthly average energy 
prices in California during June of this year, when the price cap was 
$750/MWh, were lower than monthly average energy prices during August 
of this year, when the price cap was $250/MWh--even though energy 
consumption was virtually the same in both months.

[[Page 67063]]

    Moreover, the Commission's own Staff Report suggests that there is 
a direct correlation between lower price caps and higher consumer 
prices. Specifically, it finds that decreases in the ISO price cap this 
past summer were matched by increases in exports of electricity out of 
California during the same period. The resulting decrease in net 
imports, historically relied upon by California, is one of the 
principle reasons for the increase in wholesale electricity prices.
    For these reasons, I am gratified that the Commission today decides 
to reject the price cap proposed by the PX and the purchase cap 
amendment filed by the ISO. I agree with the rest of the Commission 
that the price cap has served to keep sellers out of California markets 
and has inhibited the incentive of electricity purchasers to engage in 
forward contracting and thus hedge against price volatility and 
uncertainty.
    Unfortunately, the Commission does not stop here. Instead, it 
proceeds to take additional ``mitigation'' action that belies its 
stated intention to allow competitive markets to send price signals to 
suppliers and customers.

2. Abolish the Single Price Auction

    The Commission abandons a hard cap and imposes a soft cap in its 
place. This is accomplished through the Commission's modification of 
the single price auction. In today's order, the Commission creates two 
distinct categories of bids into the PX and ISO. Sellers bidding below 
$150/MWh will be subject to little scrutiny. Sellers bidding in excess 
of the $150 threshold, however, will be subject to tremendous scrutiny. 
Today's order explains in considerable detail all of the information 
the PX, ISO, and each seller must report for each bid in excess of 
$150. Moreover, the order states ominously that the purpose of the 
enhanced reporting requirements is not simply to monitor market 
behavior. Rather, it explains that the Commission will use this 
information ``to adjust transaction prices, if necessary, to establish 
just and reasonable rates.''
    Thus, to me, the practical effect of today's modification to the 
single price auction is to clearly disfavor all bids in excess of $150. 
While the order states that the Commission is not preventing a supplier 
from bidding in excess of that number and receiving its bid, I doubt 
that suppliers will be anxious to take advantage of that opportunity 
and to incur the Commission's wrath. I ask for comment as to whether my 
doubts are shared by the industry.
    I would simplify matters considerably. I would not select an 
arbitrary $150 figure and leave it in place for an equally arbitrary 
24-month period. Instead, I would do what numerous participants in our 
California proceeding have been asking us to do--eliminate the single 
price auction altogether.
    Despite its length, today's order is surprisingly silent as to the 
merit of abandoning the single price auction. (This is one of the 
remedial options identified in the Staff Report.) I fail to perceive 
any compelling reason why any bid should set the price for the entire 
market. If the market clearing price for the final increment of needed 
capacity is, say, $100 MWh, why should a supplier who bid a lower 
figure receive the same value as that afforded to the supplier of 
higher-priced increment? Similarly, if the market clears in excess of 
$100, why should that clearing price set the market price?
    My preference is that sellers in California be paid what they bid, 
regardless of what that bid is, rather than the market clearing price. 
I can think of no other action that would be more effective in lowering 
rates to truly competitive levels.

3. Terminate the Mandatory Buy-Sell Requirement in the PX

    This is one topic that the Commission gets right in most respects. 
Wholesale customers should have the ability to name their own price. 
The Priceline.Com model is, in its most basic form, applicable to 
wholesale electricity. Purchasers do not need the government to 
intercede to limit upside price risk. Rather, purchasers have the 
ability to do this for themselves, if government does not interfere to 
limit their ability to take advantage of financial instruments and 
contracting options.
    Today's order concludes that the existing requirement that 
investor-owned utilities sell all of their generation into and buy all 
of their requirements from the PX contributes significantly to rates 
that are unjust and unreasonable. I agree. The Commission correctly 
removes this encumbrance to trading options. Load-serving utilities 
should have full opportunity to pursue a portfolio of long- and short-
term resources and to reach whatever markets are best suited to meet 
the needs of their customers.
    Unfortunately, in its zeal to promote hedging opportunities--a 
laudable goal to be sure--the Commission goes too far. I explain later 
in this statement my objection to the Commission's decision to dictate 
to market participants how best to manage risk.

4. Direct the ISO and PX to Address Remaining Impediments in Their 
January, 2001 RTO Filing

    Today's order expends many pages addressing numerous other flaws in 
the California market design. Specifically, the order discusses reserve 
requirements, congestion management redesign, reliability and 
operational measures, governance structures, demand response, balance 
scheduling, generation interconnection, and market monitoring and 
mitigation. The Commission requires specific responses to certain of 
its concerns. It directs market institutions and participants to 
consider and report back on other concerns.
    I am greatly concerned that the Commission, in its desire to appear 
active and engaged, is greatly undermining the ability of the ISO and 
PX to make its regional transmission organization (RTO) filing. That 
filing is due to be filed no later than January 16, 2001--only 2\1/2\ 
months from now. I have no problem with the Commission identifying its 
concerns in this order. However, I would ask the ISO and PX to take 
these concerns into account when they make their RTO filing. By asking 
the ISO and PX to act immediately on some measures, relatively soon 
(short-term) on other measures, and somewhat more leisurely (long-term) 
on still other measures, the Commission is greatly inhibiting the 
ability of the PX and ISO to respond effectively to their RTO filing 
obligation. The Commission is also hindering, and in some cases pre-
judging, its ability to act on that filing once received.

Remedial Measures I Would Not Adopt

1. Modify the Single Price Auction

    I have already explained my preference for abandoning, rather than 
modifying, the auction rules used by the PX and ISO. If the Commission 
insists on modifying, rather than terminating, the single price 
auction, I would offer a different modification.
    Specifically, I would start the single price auction for all sale 
offers at or below $250 MWh. I would not lower the de facto price cap 
below the figure currently in place and previously approved (over my 
dissent) by the Commission. The Staff Report indicates (at 6-12) that 
the existing ISO cap already appears to be too low, and that it comes 
close to the variable costs (fuel and emissions) of a combustion 
turbine. The Report continues that a price cap at the existing level is 
unlikely to be high enough to attract new investment.
    If the Commission is insistent that it must have a single price 
auction dollar

[[Page 67064]]

figure in place, I would not leave it at that figure for the entire 
period of the transitional period. Rather, I would escalate that figure 
upward by specific amounts (say, $250 or $500 amounts) at specific 
intervals (say, every six months). In this manner, California market 
participants and institutions, in conjunction with California 
regulators and legislators, will have the incentive to respond 
immediately to the market design flaws identified in today's order. For 
example, the Commission has no authority to direct the state of 
California to expedite its siting and permitting procedures, or to drop 
remaining impediments to forward contracting. A price cap escalator, 
however, would act to spur all market players to adopt new and badly-
needed remedial measures.

2. Disband Stakeholder Boards at This Time

    I have no particular fondness for the stakeholder Governing Boards 
for the PX and the ISO. As today's order correctly explains, the 
decision-making process is overly complex, mired in controversy, and 
prone to excessive influence by special interest groups. In operation, 
the Boards function as little more than a debating society among 
various market participants. Their governance structure is no model for 
how a transmission grid or centralized exchange should be operated. The 
structure is certainly no model for how a competitive business should 
be run.
    Despite all of my misgivings, I would not proceed, as the 
Commission does today, to dictate right now how the Governing Boards 
should be restructured. Governance and independence are topics, I 
presume, that the ISO and PX are vigorously debating as they prepare 
their RTO filing. They very well may decide to adopt the independent, 
non-stakeholder governance structure preferred by the Commission in 
today's order. But, then again, they may not. This is ultimately a 
matter to be addressed by the ISO and PX, after consultation with 
various market participants, in the first instance and for the 
Commission to consider only after receiving the California RTO filing.
    By insisting upon a non-stakeholder structure right now, the 
Commission is betraying its principles as articulated in Order No. 
2000. The Commission stated its preference for flexibility and 
initiative. It also indicated that what works well in one region of the 
country may not work as well in other regions. I have no idea whether 
the Boards of ISOs in New York, New England, and PJM would have 
responded any more effectively and independently than the California 
ISO and PX Boards, had they been presented with similar market 
problems. Today's order assumes that governance structures in the East 
would have operated more effectively than the existing governance 
structure in the West. I would make no such assumption.
    Indeed, all of the Commission's articulated concern for 
independence and effective decision-making merely confirms my belief 
that by far the most independent and effective governance structure is 
that found in an independent transmission company. Despite my 
enthusiasm for a transco, I would not dare suggest that the Commission 
impose one on California right now in punishment for the conduct of the 
California Governing Boards this past summer.
    Finally, the Commission is needlessly provoking a constitutional 
show-down. The Governing Boards are the product of legislative 
decisionmaking. As a practical matter, I doubt they can be replaced in 
the time frame contemplated in today's order. Moreover, left 
unexplained is what the Commission intends to do if the ISO and PX balk 
at the requirement to adopt immediately a non-stakeholder governance 
structure. This is precisely the reason why the governance structure 
should be negotiated and worked out in the context of the collegial RTO 
process--not determined immediately by regulatory fiat.

3. Dictate to Market Participants How Best to Manage Risk

    I share the Commission's enthusiasm for risk management and forward 
contracting. A prudent utility, I assume, would spread out its risk and 
procure a diversified portfolio of contracts. This Commission and the 
California Commission, to the extent possible, should encourage the 
scheduling of load in forward markets (daily, weekly, monthly, 
annually, etc.) and should discourage scheduling in real-time (spot) 
markets. California utilities that failed to take advantage of forward 
contracting options, because of inattentiveness or regulatory 
inhibitions, were badly burned this past summer when real-time 
electricity prices sky-rocketed.
    Nevertheless, I draw the line at dictating to market participants 
precisely how much of their transactions to schedule in forward markets 
and how much to schedule in real-time markets. I have no basis for 
assessing what an optimal allocation between forward and real-time 
scheduling should look like. I believe that no single risk allocation 
portfolio is appropriate for all market participants. And I believe 
that no market participant should be locked into a particular 
allocation method once established. This is, ultimately, a decision to 
be made by market participants based upon their own risk tolerance and 
their own evaluation of competitive and financial opportunities. 
(Hopefully, market participants will be able to make such a decision 
now that the Commission is eliminating the mandatory buy-sell 
requirement in the PX.)
    I understand that there is a fine line between managing risk and 
operating in a reliable manner. The Commission justifiably raises a 
concern in today's order that underscheduling of load and generation in 
day-ahead and day-of markets forces the ISO to operate an energy market 
and places system reliability at risk. However, the answer to this 
concern is not to compel market participants to schedule 95 percent or 
more of their transactions in forward markets. Rather, I would prefer 
to direct the ISO and PX to address the underscheduling issue in their 
forthcoming RTO filing.

Refunds

    I choose to close with a discussion of refunds, so as to stress the 
importance of this issue.
    The Commission needs to be honest and forthright with California 
ratepayers on the subject of refunds. It is a basic premise of 
responsible government that the American public should know precisely 
where their elected and appointed officials stand. This is particularly 
true in California, as the Commission has promised in its orders and in 
its hearings that it would decide quickly and decisively whether to 
order refunds.
    I believe that the Commission has failed as to this basic 
responsibility. It is now November 1, and California ratepayers are no 
closer to a final decision on their claim to refunds for perceived 
overcharges during the summer. Today's order employs mushy and 
confusing language on the subject of refunds, indecipherable to all but 
the most devoted of FERC insiders. I would be more direct.
    As for refunds for past periods, today's order concludes that legal 
authority offers ``strong support'' for the proposition that the 
Commission lacks authority to order retroactive refunds. I would not be 
so equivocal. The Federal Power Act rests on a legislative preference 
for rate certainty. Refunds and rate revisions, absent a utility 
filing, are reserved for periods subsequent to the filing of a customer 
complaint or the initiation of a Commission proceeding.

[[Page 67065]]

I discern no exception for market-based (as opposed to stated) rates.
    I fail to see how the Commission, even if it wanted to order 
refunds for prices charged to San Diegans during the summer of 2000, 
could do so in the present circumstances. Neither the Staff Report nor 
today's order contains any finding that any power supplier exercised 
market power or otherwise engaged in inappropriate behavior. Indeed, 
neither the Staff Report nor the order reaches definite conclusions 
about any seller or category of sellers. In these circumstances, how 
could the Commission order individual sellers or categories of sellers 
to make refunds, much less allocate responsibility for refunds among 
sellers?
    Curiously, the Commission does state in a footnote that it is 
willing to consider ``other forms of equitable relief'' to mitigate the 
``severe financial consequences of last summer's high prices.'' 
Frankly, I do not know what this statement means. If the Commission 
intends to suggest that it enjoys the power to do indirectly what it 
cannot do directly--i.e., exercise its considerable powers of 
persuasion to motivate power suppliers to reimburse buyers in some 
respect--then I reject that suggestion as legally unfounded.
    As for refunds for future periods, today's order informs power 
suppliers that their sales into California ISO and PX markets are now 
``subject to refund.'' I addressed the practical effect of ``subject 
to'' language in my concurrence to the August 23 order initiating the 
Commission's investigation into California markets. 92 FERC at 61,611. 
I believe that the inclusion of ``subject to'' language will act to 
exacerbate supply deficiencies in California. This is because power 
suppliers, uncertain whether the Commission later may decide to alter 
the rate they have charged, justifiably will decide to sell their 
capacity in markets outside California. This will only accelerate the 
exodus of power outside California, a factor recognized by the Staff 
Report as contributing to the summer increase in the wholesale price of 
electricity.
    I also have serious reservations about conditioning market-based 
rate authorization on maintaining a ``subject to refund'' obligation 
through the end of 2002. This has the practical effect of extending the 
refund protection under section 206 of the FPA for a total of 27 months 
of protection. In contrast, section 206 is explicit that, absent 
dilatory behavior of the type not present here, refund relief may 
extend only 15 months from the refund effective date established by the 
Commission (here, October 2, 2000).
    To address credible claims of anticompetitive behavior, I would 
employ the Federal Power Act as it was drafted and promulgated, not as 
it arguably should be revised to recognize modern-day power sales. I 
continue to believe that the Commission should act vigorously to detect 
and remedy real abuses of market power. If a complaint or Commission 
staff-initiated investigation can establish, to the Commission's 
satisfaction, such an abuse, the Commission should order refunds 
prospective from the date of that complaint or investigation. By 
directing the imposition of a ``subject to refund'' condition on 
California sellers of power, the Commission now goes beyond the 
limitations of the FPA by allowing for the potential award of refunds 
for conduct prior to the filing of a complaint or the initiation of an 
investigation.
    Next Tuesday represents the most political day of our American 
heritage. It is our birthright as Americans. Today, there is no room 
for politics. The question is not whether or not I want to give refund 
relief to California ratepayers. I do, but I want to follow the law. I 
am certainly not above it.

Conclusion

    In conclusion, there is much I like and much I dislike about 
today's order. I believe that it is important to keep the process 
moving forward and to inform California ratepayers and officials of our 
judgments as soon as possible. I look forward to public input. I remain 
committed to respond to the needs of California ratepayers in a 
balanced manner that, hopefully, will allow them to enjoy the benefits 
of a competitive market as quickly as possible.
    For all of these reasons, I respectfully concur.

Curt L. Hebert, Jr.,
Commissioner.
[FR Doc. 00-28447 Filed 11-2-00; 2:57 am]
BILLING CODE 6717-01-P