67040 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

1San Diego Gas & Electric Company, et al., 92

FERC ¶ 61,172 (2000), reh’g pending (August 23

Order).

2See Order Directing Staff Investigation, 92 FERC

¶ 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.

4Under 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.’’

5Because 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.

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.

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 shortterm 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 hourahead markets will remain subject to the

refund conditions set forth in the

August 23 order, as discussed more

fully below.5

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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67041

6As 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. 7See 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).

8AB 1890, signed by Governor Wilson on

September 23, 1996, California Statutes 1996,

Chapter 854 (Restructuring Legislation or AB 1890).

9As 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. 10The 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. 11See Pacific Gas and Electric Co., et al., 77 FERC

¶ 61,077 (1996) (PG&E I); Pacific Gas and Electric

Co., et al., 77 FERC ¶ 61,204 (1996) (PG&E II);

Pacific Gas and Electric Co., et al., 77 FERC

¶ 61,265 (1996) (PG&E III). One area of particular

concern for

Continued

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.

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

67042 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

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.

12Pacific Gas and Electric Co. et al., 81 FERC

¶ 61,122 (1997) (October 30, 1997 Order).

13Among 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.

14See AES Redondo Beach, L.L.C., et al., 84 FERC

¶ 61,046 (1998), order on reh’g, 85 FERC ¶ 61,123

(1998) (October 28 1998 Order), order on further

reh’g, 87 FERC ¶ 61,208 (1999) (May 26, 1999

Order), order on further reh’g, 88 FERC ¶ 61,096

(1999), order on further reh’g, 90 FERC ¶ 61,148

(2000). See also California Independent System

Operator Corporation, 84 FERC ¶ 61,309 (1998).

15October 28, 1998 Order, 85 FERC at 61,462.

16See May 26, 1999 Order, 87 FERC at 61,801–

02 (explaining that the ISO developed a phased

approach to the redesign).

17 85 FERC at 61,463.

18California Independent System Operator

Corporation, 86 FERC ¶ 61,059 (1999).

19 87 FERC at 61,817–19.

20California Independent System Operator

Corporation, 89 FERC ¶ 61,169 (1999), reh’g

pending.

21Price Movements in California Electricity

Markets: Analysis of May–June 2000 Price Activity,

PX Compliance Unit, September 29, 2000 at 10.

22Report of California Energy Market Issues and

Performance: May–June 2000, ISO Department of

Market Analysis, August 10, 2000 at 13.

23Natural gas comprises about 55 percent of

California’s fuel mix.

24Staff Report at 3–21.

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

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

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

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.

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

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.

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

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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67043

25The 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.

26On 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.

27See Electric Utility Week, Oct. 9, 2000, pp. 5–

6.

28See infra, note 2.

29Morgan Stanley Capital Group Inc. v.

California Independent System Operator

Corporation, 92 FERC ¶ 61,112 (2000) (Morgan

Stanley).

30 92 FERC at 61,606. (Commissioner Massey

dissented on this point).

amount recovered in retail rates by

billions of dollars.25

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

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 factfinding 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.

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

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.

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 realtime 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

67044 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

31The 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.

32A 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. 33August 23 Order at 61,606.

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

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 Dayof 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).

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.

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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67045

34On 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.

35As 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 ¶ 61,078 and

73 FERC ¶ 61,219 (1995).

36California’s import capability is approximately

8,000 MW.

37Two 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.

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.

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

67046 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

38See Staff Report at 1–3, 3–15—3–17.

39There 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.

40Staff 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.

43An 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.

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

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

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.

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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67047

44We 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.

45 Initially, the PX administered only a Day-ahead

and an hour-ahead (Day-of) spot Market. Later, it

added limited forward marketproducts.

46Section 368 of AB 1890.

47The 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.

48While 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.

49PG&E, SoCal Edison, and SDG&E still control

26 percent, 20 percent, and 1 percent, respectively,

of in-state generation and purchase power contracts.

50The Staff Report reached a similar conclusion.

Staff Report at 5–9 and 5–11.

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.

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.

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

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.

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 shortterm resources and access whatever

wholesale markets are suited to meeting

the needs of their retail customers

67048 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

51The 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.

52The PX Day-of Market is the hourly energy

market that is scheduled with the ISO at least 2

hours in advance of real time.

53Underscheduling occurs when an entity

schedules significantly less energy than its expected

actual consumption.

54Staff Report at 5–14 and 5–16.

55See ll FERC at .

56August 25, 2000 Memorandum from Mr.

Winter to ISO Board of Governors.

57 92 FERC at 61,108.

58We 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.

59See, e.g., Indiana Michigan Power Company, et

al., 44 FERC ¶ 61,313 at 62,078 (1988).

60See also Section C3. Balanced Schedules

below.

61PG&E II.

(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.

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.

The record indicates that there is a

chronic pattern of underscheduling 53

load and generation in the PX’s DayAhead 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 outof-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.

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

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 realtime 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.

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.

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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67049

62See 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. ¶ 31,036 (1996) (Order No. 888), order on

reh’g, Order No. 888–A, 62 Fed. Reg. 12,274 (1997),

FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g,

Order No. 888–B, 62 Fed. Reg. 64,688, 81 FERC

¶ 61,248 (1997), order on reh’g, Order No. 888–C,

82 FERC ¶ 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. 64See 77 FERC at 61,818.

65 81 FERC at 61,451–53; see also California

Power Exchange Corp., et al., 85 FERC ¶ 61,263

(1998).

66 85 FERC ¶ 61,264 at 62,068.

67See California Electricity Oversight Board, 88

FERC ¶ 61,172 (1999), reh’g denied, 89 FERC

¶ 61,134 (1999), appeal docketed, Western Power

Trading Forum, et al., v. FERC, No. 99–1532 (D.C.

Cir.) (Oversight Board).

68These 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.

69Staff Report at 6–17.

70September 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.

72Letter of resignation of Camden Collins, dated

July 3, 2000.

governed by boards composed of

individuals residing in California who

were chosen to represent various

stakeholder classes (i.e., transmission

owners, municipal entities, sellers, endusers, 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.

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

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

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.

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

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

67050 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

73California ISO Board of Governors Meeting

minutes, 28 June 2000, p. 89.

74Staff Report at 6–17, 6–18.

75California’s Electricity Options and Challenges:

Report to the Governor, Executive Summary at 3–

4 (Joint Report).

76As 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. 77 81 FERC at 61,552.

78This requirement is consistent with the

recommendation in the Staff Report at 6–18.

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

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

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 nonstakeholder 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, nonstakeholder 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.

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.

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67051

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.

80The 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

Continued

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 ¶ 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

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 shortterm 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

67052 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

outside California. See Staff Report at pp. 5–2 to 5–

7.

81The 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.

82Staff Report at 5–19. 83Price 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.

84 In order to encourage the expansion of Demand

Response programs, we will not extend this market

reform to bids for load response. 85For 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.

86This 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.

87The 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.

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.

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.

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 shortterm 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 asbid 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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67053

88Natural gas comprises about 55 percent of

California’s fuel mix.

89Staff Report at 3–21.

90Average 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.

91A 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.

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.

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

67054 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

92However, given the new and dynamic

environment, the Commission is willing to explore

any proposal for equitable relief, provided that it

breakpoint will be paid the as-bid price,

but will be required to report so that we

can monitor their bids.

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 selfcorrect, 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

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67055

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.

93 92 FERC at 61,606.

94We leave undisturbed the ISO’s $100 purchase

price cap for Replacement Reserves during this time

period.

95We 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.

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 marketbased 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 outof-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

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

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

67056 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

96See 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.

97The use of a ‘‘paper’’ hearing rather than a trialtype evidentiary hearing has been addressed in

several cases. See, e.g., Public Service Company of

Indiana, 49 FERC ¶ 61,346 (1989), order on reh’g,

50 FERC ¶ 61,186, opinion issued, Opinion 349, 51

FERC ¶ 61,367, order on reh’g, Opinion 349–A, 52

FERC ¶ 61,260, clarified, 53 FERC ¶ 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.

process and, therefore, most likely to be

completed in the shortest time 96.

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.

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 He ́bert 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

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

67058 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

98Section 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.’’

99 102 Stat. 2299 (1988). The RFA amendments to

section 206 are discussed infra.

100As 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.

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.

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.

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

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

§ 206 of the FPA to permit specifically

limited retroactive refund authority.

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67059

101Proposed 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.’’

102See, e.g., City of Bethany v. FERC, 727 F.2d

1131 (D.C. Cir. 1984), cert.denied, 469 U.S. 917

(1984).

103The House passed H.R. 2858, a Senate

Committee amended the House-passed bill, and the

Senate passed H.R. 2858, as amended.

104S. Rep. No. 491, 100th Cong., 2d Sess. 3–4

(1988), reprinted in 1988 U.S.C.C.A.N. 2685.

105S. Rep. No. 491 at 5, reprinted in 1988

U.S.C.C.A.N. 2687.

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.

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.

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:

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

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

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:

67060 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

106S. Rep. No. 491 at 5–6, reprinted in 1988

U.S.C.C.A.N. 2687–88.

107Towns 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).

108Towns 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.’’).

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

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

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

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. §§ 205(e), 206(a), 49 Stat.

852, 16 U.S.C. §§ 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 ¶ 61,032 at 61,088

(1987). The Commission may also be able to

order refunds as a remedy to correct legal

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67061

109The court determined that the Commission

had committed legal error.

110 15 U.S.C. § 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.

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’’).

D. Applicability of the Refund Provisions of

Sections 205 and 206 and the Filed Rate and

Retroactive Ratemaking Doctrines to MarketBased 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 Commissionapproved rate, whether cost-based or marketbased, 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 marketbased 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 socalled 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 muchneeded generation.

67062 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

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.

He ́bert, 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 illequipped 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.

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 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 investorowned 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 21⁄2 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

67064 Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices

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.

Federal Register / Vol. 65, No. 217 / Wednesday, November 8, 2000 / Notices 67065

1San Diego Gas & Electric Company, et al., 93

FERC ¶61,051 (2000).

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. He ́bert, Jr.,

Commissioner.

[FR Doc. 00–28447 Filed 11–2–00; 2:57 am]

BILLING CODE 6717–01–P

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 Meetng in San

Diego, California; California Power

Exchange Corporation; California

Independent System Operator

Corporation; Order specifying time of

conference and procedure for seeking

participation

Issued November 1, 2000.

Before Commissioners: James J. Hoecker,

Chairman; William L. Massey, Linda

Breathitt, and Curt He ́bert, Jr.

In this order, the Commission

specifies the time and place for the

November 9, 20009 public conference

announced by Commission order on

October 19, 2000, 1 and the procedure

for interested persons to follow in

seeking participation in the conference.

Background

On October 19, 2000, in the

consolidated dockets listed above, the

Commission issued an order

announcing in advance the procedures

it expects to follow over the coming

weeks to move forward in these

proceedings. Among other things, the

Commission indicated that it expected

to hold a public conference on

November 9, 2000 to discuss proposed

remedies and stated that a separate

order would be issued to specify the

date and time of the conference and the

manner for seeking participation in the

conference.

Discussion

Time and Place of Conference

The Commission announces that it

will convene a public conference to be

held on Thursday, November 9, 2000, at

the offices of the Federal Energy

Regulatory Commission, 888 First

Street, NE., Washington, DC 20426. The

conference will commence at 9 a.m. and

will be open to all interested persons.