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6. Policy Options

This section discusses some of the options available to the Commission or state agencies, with

encouragement by the Commission, to correct the conditions that led to the unusually high and volatile

prices in the West during the summer of 2000. Those conditions were: a general shortage of

generation throughout the West, an over-reliance on spot market purchases by the IOUs in California,

insufficient demand responsiveness to price, and a highly politicized process for setting price caps for

the Cal-ISO. The options are summarized below first and then discussed in the following section.

To encourage investment in new generation:

! Adopt policies that encourage and facilitate the investment in new generation. Tight

generation resources were a major factor contributing to high prices. Easing local siting

approval processes in California could encourage more investment and ultimately bring

on more electricity supply. At the federal level, the Commission's wholesale price

policies have an important effect on investment decisions and should be designed to

create incentives to spur new investment in generation and transmission.

To remedy the over-reliance on spot market purchases:

! Eliminate the requirement that the three California IOUs must buy and sell through the

PX. This can be implemented by the Commission (1) requiring a change in the

eligibility provisions of the PX tariff or (2) changing its policies applicable to wholesale

spot markets.

! Require the IOUs to hedge and forward contract through the PX and bilateral

transactions. This can be implemented either by the CPUC or by the FERC.

! Require all in-California thermal generation capacity to be bid into the forward

California markets. This option might increase the amount of capacity available in the

forward markets. 

To provide more demand response to wholesale prices:

! Encourage California to implement policies to increase retail demand responsiveness to

price. The Commission has no authority over retail rates in California; however,

California may undertake retail market reforms that will greatly benefit wholesale

markets. Competition among energy service providers for the retail load of the IOUs

would create strong downward pressure on the price of energy in California. Just

allowing large retail consumers to face the price in the wholesale market would provide

more demand responsiveness to the wholesale market. If state policy is to allow load

serving entities to pass through the costs of energy and ancillary services directly to
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retail customers, then those customers should be given some way to respond to those

prices. If state policy continues to regulate retail service by the IOUs, then the IOUs

should be given strong incentives to minimize their wholesale purchase costs.

! The Commission can stimulate greater demand response for the wholesale market by

requiring the California ISO to allow scheduling coordinators to bid load responses in

the ancillary services market (reserves, etc.). Scheduling coordinators could receive

bids from those willing to provide a load reduction and then bid those in the ancillary

services market. The scheduling coordinators could arrange with the ISO, on a

bilateral basis, terms such as price and performance measures. 

To provide some price regulation while generation resources remain scarce

and until regulatory changes are made to provide more demand response:

! The Commission could return to traditional cost-of-service regulation for generators in

California. There is the potential that this option could result in relatively high rates if the

acquisition premiums of the non-utility owners are taken into account. Also, this

alternative may be inconsistent with an objective to encourage investment in new

generation.

! The Commission could adopt limited term price caps for spot market sales (day-ahead

and hour-ahead) in both the PX and the Cal-ISO. The price caps would apply for a

fixed 18-month period, the period in which generation is currently predicted to remain

scarce, and would allow time to develop a regulatory structure to provide greater

demand response. The cap would be set at a level that would permit recovery of

current marginal costs, including opportunity costs, and be high enough to encourage

new investment. An alternative would be to apply this limited-term price cap to all

short-term wholesale sales in the West.

! Alternatively, the Commission could adopt a limited-term price cap to apply to longterm sales in addition to spot market sales. Since wholesale forward prices in

California are also high, as a result of conditions last summer, the Commission could

also adopt a temporary price cap to apply to long-term sales, to allow time for new

generation to enter the market and for the regulatory structure to permit greater demand

response. This option could have the effect of discouraging new investment, particularly

if investors rely on forward prices to signal the need for new investment.

! As an alternative to a price cap on long-term prices, the Commission could adopt target

prices for long-term contracts in the California market, based on pre-summer prices. 

These would apply for an 18-month period as described in the price cap options

above. Wholesale sellers that substantially exceed the target prices would be subject to
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close scrutiny to determine whether they are exercising market power, with a potential

loss of their market-based rate authority. 

! The Commission can leave the spot market and long-term market prices unconstrained. 

With the evidence of scarcity in the region, higher prices produced by the market may

be the right stimulus to needed new investment. This option would be more effective if

coupled with actions to improve the overall functioning of the market, such as improving

demand responsiveness and minimizing the reliance on spot market purchases. The

option can be coupled with increased monitoring of market participants for evidence of

market power abuse.

! The Commission can implement locational market power mitigation measures,

independent of the options for price caps.

! The Commission could change the auction rules used by the PX and the Cal-ISO to

pay sellers what they bid rather than the market-clearing price. This option can be

adopted independent of other pricing options.

To create a more stable regulatory environment:

! The Commission can abolish the current stakeholder governing boards of the Cal-ISO

and the PX and require independent, non-stakeholder boards. This would also

eliminate the need for the EOB, which could be abolished also. 

! The Commission can retain the sole authority to impose price caps in wholesale market

transactions and not delegate that authority to the Cal-ISO or the PX.

! Require the Cal-ISO and PX market monitors to report directly to the FERC any

evidence of market power abuse for evaluation and action by the Commission, without

prior review by their boards.

Other options:

! To eliminate underscheduling in the Cal-ISO, the Commission can change the incentives

for suppliers to sell in real-time and require stronger penalties for real-time purchases,

combined with increased options for IOUs to have broader supply portfolios.

! The Commission could direct a further investigation of generators with abnormally high

unplanned outage rates or bidders into the PX to examine whether individual market

participants may have engaged in withholding or price manipulation. This option could

be coupled with increased reporting to the Commission, as discussed in other options.
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Discussion of Options

1. Encourage Investment in New Generation

Most projections for new generation capacity additions indicate that a significant amount of new

capacity is planned to be available in 2002. Until new generation is added in the West, high prices can

be expected to recur. While high prices are necessary to stimulate investment in new generation,

barriers to the entry of new supplies into the market will result in a longer period of high prices than may

be necessary. Federal, state and local regulatory policies should be designed to eliminate unnecessary

barriers to new generation and to create incentives for new investment. 

Specific rules about siting and local approval processes are within the control of state and local

policymakers. Some steps have been taken in California to speed the local approval, but there may be

more things that can be done. 

At the federal level, Commission pricing policies can have an important impact on investment

decisions. If wholesale prices are kept too low through regulatory controls, this can cause investors to

invest in other markets. For example, if the Commission imposes wholesale price caps in California

that are too low, generators may choose to build in Arizona or Nevada where there would be no price

caps but where there is a growing demand for power. To provide an incentive for new generation to

be located in California as well as other western states, the Commission may need to explicitly take into

account the need to stimulate new investment through pricing policies.

Another factor that affects investment decisions is the stability of the regulatory process. To

finance new generation plants, firms need to be able to convince their investors that the regulatory

environment is stable enough to assure a return over the life of the project. This past summer's

experience with the constantly changing Cal-ISO price caps created instability for the market and

aroused investor concerns about investing resources in California. Therefore, stability in pricing policies

can be a factor in encouraging investment in new generation.

2. Remedy the Over-Reliance on Spot Market Purchases

Spot markets are inherently volatile. In eastern bulk power markets with an ISO only 10 to 20

percent of the load is served by spot market purchases, but in California almost 100 percent of the load

served by the IOUs is served by purchases in the spot market. Shifting purchases out of the spot

market to longer term contractual arrangements would create greater price stability for wholesale

buyers and end-users. In this market context, day-ahead and day-of purchases are spot market

purchases. Forward contracts, for purchases longer than day-ahead and day-of, are longer term

contracts. 
1Pacific Gas & Electric Co. et al., 77 FERC ¶61,265 at 62,088 (1996).

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Forward contracts for energy potentially can provide IOUs and other load serving entities with

a highly effective hedge against high costs in energy spot markets, while providing both buyers and

sellers with a greater level of price certainty. If generators are otherwise able to exercise market power

in energy spot markets, such contracts can help to mitigate the market power of the generators that

contract to sell their output at a fixed price. Thus, forward financial contracts offer the potential to

reduce both the cost impact of price spikes on consumers' bills, and the incidence and magnitude of the

price spikes that occur.

There are several options available to shift purchases to forward contracting:

Eliminate the requirement for the three California IOUs to buy and sell through

the PX. During the summer of 2000 the IOUs had limited authority to enter into forward contracts. 

The block-forward contract available to them through the PX is insufficiently flexible to provide them

the full benefits of forward contracting. Eliminating the restrictions on their ability to forward contract

and to purchase supplies outside the PX would provide them with the ability to create portfolios of

supply contracts to get more stable energy costs. While the CPUC recently expanded the authority of

the IOUs to enter into bilateral, long-term contracts, this authority is still limited.

These restrictions could be eliminated directly by the Commission through actions it could take

within its wholesale jurisdiction. When the Commission originally approved the restructuring proposals

of the IOUs, it found that any concerns it might have about the requirement at that time were

outweighed by other considerations.1 The Commission could now find that such restrictions have

become an impediment to the stability and proper functioning of the wholesale market and require a

change in the eligibility provisions of the PX to insure that any wholesale buyers in the PX have the

ability to buy their supply from other sources, or could otherwise establish a similar condition as a

prerequisite to the IOUs transacting business in the wholesale market.

One of the original reasons for the mandatory buy/sell requirement was a concern for potential

affiliate abuse in the buying and selling of energy. There are other ways to deal with this concern. For

example, the IOUs could be required to use most-favored nations clauses for any transactions with

affiliates to ensure that the price agreed to in an affiliate deal is no higher than the prices paid to nonaffiliates. 

Require the IOUs to hedge and forward contract. This is a variant of the option

discussed above. The difference is that, rather than just eliminating an impediment to hedging and

forward contracting, the option goes a step further to require the use of these tools. This could be done

as a requirement to purchase a certain percentage of a supply portfolio through different instruments,

and it could be implemented either by the CPUC or the Commission in the same way as the option

above. It has the disadvantage of substituting the judgment of regulators for the judgment of business
2Forward market sales in this context could also include purely financial hedges, such as

“contracts for differences,” where a buyer and seller agree in advance to a contractually-specified price

(called a “strike price”) for a specified quantity. Then, after the real time market closes, the buyer and

seller agree to make additional payments to each other based on the difference between the real time

spot price and the strike price.

3

In addition, regulatory must run and must take generators would continue to be required to bid

into the PX energy market at $0, as they are currently required to do.

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managers as to the best way to create a balanced supply portfolio. Providing business managers with

financial incentives for managing their business in a way that minimizes costs is usually a more effective

regulatory strategy. 

Require all in-California thermal generation capacity to bid into the California

forward markets. This option is the flip-side of the option above. It may increase the amount of

capacity made available in the forward markets and it would allow generators to arrange sales in the

forward markets at whatever prices they can negotiate. Thus, forward market sales would be market

based, and generators would be free to pursue their most profitable opportunities.2 However, as an

incentive to get the maximum amount of thermal capacity available in the forward markets, thermal

generators would be required to submit bids at the generator's marginal operating cost in the ISO's real

time market for any unsold capacity.3 Enforcing such a requirement would prevent generators from

withholding capacity from the market, so prices in the real time market would not be inflated due to the

exercise of market power. In addition, suppliers would have less ability to exercise market power in

the forward markets, because buyers could avoid inflated forward market prices by buying in the realtime market. 

A requirement to bid at marginal operating cost does not take into account a generator's

opportunity cost, which may exceed its marginal operating cost when other markets are transacting at

higher prices. But while thermal generators may have opportunities to sell in multiple markets in

advance of real time, those opportunities fade as real time approaches. By the time the real-time

market is operating, a thermal generator has no opportunity to sell elsewhere if its bid is rejected, so it

has no opportunity costs.

This requirement is an option for most thermal generators, but not for hydro generators or for

other generators with an absolute limit on the amount of energy that they can produce. That is because

these latter generators may face opportunity costs in real time, because production in one hour may

reduce the amount of production that can occur in subsequent hours. For example, hydro generators

often have a limited supply of their energy source (water), so producing electricity in one hour reduces

the amount of water available to generate electricity in a subsequent hour. Thus, by producing

electricity in one hour, a hydro generator foregoes the opportunity to receive revenue in a subsequent

hour. By contrast, most thermal generators do not face a limited supply of their energy sources, so
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producing electricity in one hour does not reduce the amount of electricity that can be produced in

subsequent hours. However, certain thermal generators may face absolute limits on the amount of

energy that they can produce or on the amount of time that they are permitted to generate, for example,

due to environmental regulations. Since California has a significant amount of old thermal generators

subject to emissions limitations, this may not be an attractive option.

Another criticism of requiring generators to bid previously uncommitted capacity into the realtime market is that it may encourage too much reliance on the real time market and too little scheduling

in the forward markets, and thus may create operational and reliability problems for the ISO. If overreliance on the real time market creates undue operational problems, the option could be modified to

require generators to bid into the PX's day-of energy market (rather than the real time market) at

marginal operating costs. This option would still give generators the opportunity to arrange sales in

other forward markets at advantageous prices before the Day-of market closed, although it would

reduce slightly the time available to do so. 

There are several options for establishing when the bidding requirement could be triggered. 

One option is to impose the requirement on all generators at all times. This option might be chosen if

market power arises frequently, or if it is difficult for the ISO to predict in advance when market power

will arise. Alternatively, if the ISO can accurately forecast when and where market power is likely to

arise, the bidding requirement could be imposed in more limited circumstances. For example, if market

power arises only during high demand periods, the bidding requirement could be imposed only when

the ISO forecasts load in an hour to exceed a specified level. Or, the bidding requirement could be

imposed on generators in defined areas when transmission constraints arise that create locational

market power.

By differentiating between generators within California and generators outside California, this

option can have the effect of balkanizing the wholesale market and discouraging new investment in

generation in California. Also, it may be difficult to administer and enforce.

3. Provide More Demand Response to Wholesale Prices

Encourage California to implement policies to increase retail demand

responsiveness to price. There are retail market reforms that California can take that would greatly

benefit the wholesale market by creating more demand responsiveness. 

In well functioning competitive markets, both suppliers and consumers are able to see and

respond to market prices. Indeed, this is what allows competitive markets to achieve the efficient

outcomes for which they are well noted. However, in electricity markets, such as those in California,

consumers often must make their consumption decisions without knowledge of the true market price of

electricity. Currently, most California consumers (those served by PG&E and Southern California

Edison) do not face wholesale electricity prices because of a retail rate freeze. The resulting lack of
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demand responsiveness to wholesale prices can, at times, lead to excessively high wholesale prices. 

When supply is scarce relative to demand, competitive prices will rise to a level that reflects the value

that the marginal consumer places on additional consumption. This additional increment above marginal

running cost is referred to as the “scarcity rent.” However, market prices in electricity markets like

those in California cannot be expected to settle at this level if consumers do not have the ability to see

these prices and to make known to the market, through their purchasing decisions, the value that they

place on marginal consumption. Indeed, in the absence of demand responsiveness, prices in California

and in markets elsewhere frequently rise well above this competitive level at times when demand is high

and capacity is scarce. 

One way to allow retail consumers to respond to wholesale prices is for retail rates to reflect

wholesale prices. However, to ensure that retail consumers can respond effectively to wholesale

prices, they should have some advance notice of the change in retail rate policy, so that they can

prepare for the new retail rate design. In the meantime, their traditional service providers should face

incentives to procure electricity for their customers at least cost. California policymakers could also

increase demand responsiveness to wholesale electricity prices by encouraging greater retail

competition.

California should consider, in the long term, reevaluating the status of IOUs as providers of both

distribution and energy services to their retail load. While California formally permits retail customers to

choose among alternative suppliers, in practice few new retail energy service providers have entered the

market thus far. Greater competition among energy service providers for the retail load of the IOUs

would create a strong downward pressure on the cost of energy in California. Promoting greater retail

competition likely would require a formal separation of the IOU distribution service functions from any

continuing role as an energy service provider. In addition, consideration may have to be given to

changing the CTC recovery mechanism and to imposing a provider-of-last-resort obligation on the

IOU. Also, consideration should be given to providing large retail consumers of IOUs, the traditional

retail service providers, with real-time price signals that would allow them to respond to the wholesale

prices. 

 As long as California regulates retail service provided by IOUs, then the IOUs should be

given strong incentives to minimize their wholesale costs. Regulations should be avoided that allow load

serving entities to pass through the costs of energy and ancillary services directly to retail customers

without giving those customers the ability to respond.

The Commission can stimulate more demand response for the wholesale market

by requiring the Cal-ISO to allow scheduling coordinators to bid load responses in the

ancillary services market. To implement this option, scheduling coordinators could receive bids

from any user willing to provide a load reduction. The scheduling coordinators could arrange with the

ISO, on a bilateral basis, the terms such as price and performance measures. This would not obviate

the need of the CPUC to design demand response mechanisms for the retail market, but it is an option

available to the Commission independent of the retail regulation.
4The volume would increase substantially if cost-based rates were applied to generation

owners outside of California (the entire WSCC) for their sales into the California market. 

5See Minnesota Power & Light Company and Northern States Power Company, 43 FERC ¶

61,104 at 61,342 (1988). 

6-9

4. Provide Some Price Regulation While Generation Resources

Remain Scarce and until Regulatory Changes Are Made to

Provide Greater Demand Response

The Commission could return to traditional cost-of-service regulation for

generators in California. Traditional cost-of-service regulation is used when the market cannot be

relied on to keep prices within a reasonable range because the regulated company exercises monopoly

power. Under traditional cost-of-service ratemaking, a company is allowed to recover its prudently

incurred fixed and variable costs plus its cost of capital including a reasonable return on its investment. 

Fixed and variable costs include operation and maintenance expenses (including fuel and emission

allowances), depreciation, and taxes. The return on investment is calculated by multiplying the rate of

return times the jurisdictional public utility's rate base. Rate base is calculated by subtracting from gross

plant in service any accumulated reserve for depreciation associated with that plant and adding or

subtracting from the net plant value any adjustments to rate base (such as accumulated deferred income

taxes). 

Prior to the divestiture of generating assets in California, jurisdictional utilities recorded these

expenses consistent with the Commission's Uniform System of Accounts and annually filed a FERC

Form 1 detailing their operating expenses including specific generating plant data in accordance with the

Uniform System of Accounts. However, the new owners of the divested generating units are no longer

required to follow the Commission's Uniform System of Accounts; nor are they required to file with the

Commission a FERC Form 1. Therefore, the data needed to calculate a traditional cost-of-service rate

is not currently collected and would have to be acquired. Determining a cost-based rate for every

generation owner in California would involve numerous filings dealing with complex cost-of-service

issues such as the appropriate depreciation rate for the unit, how income taxes would be calculated,

capital structure, and the appropriate rate of return.4 In addition, these cost-of-service issues may deal

with issues of first impression because the new owners of each unit are, in many instances, limited

liability corporations or partnerships. This is likely to be a complicated, time-consuming, administrative

process. 

The new generation owners purchased the divested generating assets of the IOUs for a

premium over their net book value. In the past, the Commission has permitted the inclusion of

acquisition adjustments in rate base for wholesale rates only if a utility can show that the investment

decision is prudent and if it can demonstrate that the acquisition provides measurable benefits to

ratepayers.5 The Commission would need to address the prudence and benefits of these acquisition
6-10

adjustments. If the Commission recognizes this premium in setting the new cost-based rates, the rates

for these assets would be substantially higher than when the IOUs held the same assets prior to

divestiture.

An alternative to including the full amount of the acquisition premium in the cost-of-service rates

would be to exclude the acquisition premium from rates or offset the total acquisition premium by the

amount that the generator made in the market (either this summer or since the transfer took place) over

what it would have made under competitive circumstances. Either option would depress the value of

the companies that purchased the generation assets and could present disincentives to future purchases

of divested utility assets as part of retail access in other parts of the country. 

Finally, if the Commission were to impose cost-of service rates for all wholesale sales in the

California market, the Commission would also need to calculate cost-of-service rates for any remaining

wholesale sales made by the three IOUs. The premiums received by the IOUs for their divested assets

were used as an offset to their stranded costs. Any determination of a cost-of-service rate for the

IOUs would need to take into account the total acquisition premium that was received by the IOUs to

pay down the value of their stranded assets. The new cost-of-service rates for these assets should be

lower than under the old regulated structure; however, whether the decrease in rates for these assets

would offset the higher rates for the divested assets could only be determined after the Commission has

had the opportunity to analyze all of the cost-of service rates for generation owners within California.

Traditional cost-of-service regulation is a reasonable option where the regulated firm exercises

substantial market power, such as a natural monopoly, but is ill-suited to markets where firms have

market power but also face some competition. Traditional cost-of-service regulation does not allow

the firm the flexibility to respond to market signals, for example to lower prices, and still earn its allowed

reasonable return because it cannot raise prices enough at other periods to compensate for the lower

price periods. In those cases, other forms of price regulation are better suited. In the West,

Commission regulated generators face competition from public power and power marketers, so

traditional cost-of-service regulation may not be appropriate. In addition, traditional cost of service

regulation is an administratively costly method of regulation because it is resource intensive, both for the

regulatory agency and for the regulated firm. It can add significant transaction costs to an industry that

may not be commensurate with the amount of protection it would provide in a particular context. 

Finally, a return to cost-of-service rates, even for an interim period, would create regulatory uncertainty

that would likely exacerbate existing supply problems within California, and would have an adverse

rippling effect in other electric markets in the country.

The Commission could adopt limited term price caps for spot market sales (day

ahead and day of) in both the PX and the Cal-ISO. To give some protection from high prices

until new generation plants are expected to come on line in 2002, and to provide time for the

development of regulatory changes to stimulate greater demand response and thus better price signals

for the wholesale market, the Commission could impose price caps on the spot market in California. 
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To provide certainty for the market the cap should be imposed for a limited, fixed duration and, if the

level of the cap changes, the changes should occur in predictable ways.

In addition to certainty and predictability, there are some other factors to be taken into account

in setting a price cap. Ideally a price cap should be high enough to attract generation investment to the

market, but low enough to provide protection to consumers during the short-term. It should be high

enough to permit the recovery of current marginal running costs and opportunity costs and provide a

stimulant to new investment. Another consideration is that the price cap on the spot market should be

high enough to provide an incentive for buyers to enter into long-term contracts. It also should apply

equally to all sellers in the market so, for example, sales in the PX would be capped at the same price

as sales to the Cal-ISO.

The existing ISO buyers' cap appears to be too low. The current cost data show that at the

end of the summer it started to come very close to the variable costs (fuel and emissions) of a

combustion turbine. As the costs of generating electricity have gone up the price cap has gone down,

narrowing the band of prices traded. A price cap at this level is unlikely to be high enough to stimulate

new investment.

The Commission could set the price cap at the cost of entry into the California market. One

difficulty with this choice is choosing the type of capacity that would enter the market. The cost of entry

could be the cost of transmission expansion that would increase the import capability into California or

it could be tied to the cost of a new generating unit. Since transmission capacity did not appear to be a

significant constraining factor contributing to high prices in the West this summer, the cost of a new

generating unit may be a more logical choice. The cost of a new generating unit could vary greatly

depending upon whether the unit entering the California market is baseload, intermediate or peaking

capacity.

Alternatively, the Commission could set the price cap using a formula tied to the marginal cost

of the highest cost unit in the WSCC. This would provide a transparent price, reflect the actual cost of

generation that could reach the California market, and would still be high enough to attract new, lower

cost capacity to California. Determining the actual cost of this benchmark unit may be difficult,

however, because it would require obtaining short run marginal cost data for all units in the WSCC to

discover the highest cost unit, and then trying to determine the opportunity costs of this unit.

The Commission could choose to bifurcate the market and impose a price cap when load

exceeds a specified level. Data supplied from the ISO indicate that the market deviates from normal

operating conditions when load exceeds 35,000 MW. The Commission could impose a price cap

when load exceeds this level. All price caps, unless set very high, have the effect of removing incentives

for wholesale buyers to hedge against peak prices because the cap protects against high prices. 

However, this particular price cap option appears to highlight that effect since the price cap would

become binding only at the time when scarcity becomes a serious factor. This could have a dampening
6A WSCC price cap of this type would only apply to transactions that are comparable to the

PX and ISO markets, i.e., on day-ahead and hour-ahead trades. 

7

“Power Points: Winners in $4 Billion Calif Sweepstakes,” Dow Jones Energy Service (Sept. 

29, 2000) (BPA, Salt River Project, LADWP and BC Hydro sold significant amounts of power.)

6-12

effect on the forward market and would not provide needed incentives for shifting purchases out of the

spot market into the long-term market.

To provide certainty to the market, any price cap that the Commission chooses would need to

be a hard cap that does not change during the transition period, or if it does change the changes should

occur in predictable ways. The ISO changed its buyers' cap twice during the summer. These rapid

changes in the ISO's buyers' cap created significant uncertainty for both power suppliers and buyers. 

This uncertainty increases the likelihood that suppliers will transact in more stable markets outside of

California. In addition, it has been alleged that changes to the ISO's buyers' cap caused contractual

problems for some participants in the California market that may have hedged at a price that was higher

than that permitted under the most recent buyers' cap.

An alternative to a price cap for just the California market would be to apply the price cap to

the entire WSCC.6 Applying price caps just to California could balkanize the western wholesale

market and cause power to be exported from California to other states without a cap, causing

continued shortages and high prices in California. On the other hand, it may be unnecessary to apply

price caps to the entire WSCC since prices at other hubs in the WSCC were highly correlated with

California prices. Thus, prices throughout the WSCC could be expected to track capped prices in

California, even if the cap is not extended to the entire WSCC. A potential problem with applying a

WSCC-wide price cap is that approximately 50 percent of the installed generating capacity in the

WSCC is nonjurisdictional and would not be subject to the cap. Governmental entities sell their excess

power in the wholesale market and, as was seen this last summer, the amounts sold can be significant.7

Thus the cap would be inapplicable to a large portion of the WSCC market and therefore could be

ineffectual.

 As previously noted, there are several potential levels for a price cap; however, whatever price

cap is chosen, it should terminate at a predetermined time. Since the reasons for imposing a price cap

would be to provide time for new generation to come on line and time for regulatory structures to be

developed to provide a demand response, it would be reasonable to tie a price cap to a specified

period needed for these changes. Significant new generation is currently planned to be on line in 2002,

so an 18-month period would be reasonable. This should provide the time needed for California to site

new generation as well as time to make necessary changes to its retail market structure to improve

demand responsiveness. If California does not implement the reforms needed at the state level, the

Commission should not extend the date. The market needs certainty and the high prices that result from

scarcity should be felt by wholesale buyers and end-users so they can make rational choices about their
6-13

energy consumption. Californians are unlikely to be able to decide the relative values they place on

environmental issues, public participation in governmental decision making, and electricity usage, or the

value of obtaining supplies from the grid or from other sources, unless they know the cost of these

choices.

Instead of a specified date, another option would be to terminate the price cap when the

reserve level for the California market reaches a certain percentage. Under this option, a reasonable

percentage could be established at a planning reserve number tied to the annual peak for the California

market. Terminating the price cap when the specified reserve level is achieved should prompt

generation expansion in California because the sooner generators increase their generation capacity the

sooner the cap will be removed. This also provides certainty for investors that the rules are fixed and

will not change. This may, however, diminish incentives for the state to expedite the siting of new

generation.

Alternatively, the Commission could adopt a limited-term price cap to apply to

long-term sales in addition to spot market sales. Since wholesale forward prices in California

are high, as a result of conditions last summer, the Commission could also adopt a temporary price cap

for long-term sales. The rationale for this cap would be the same as the spot market cap—to allow

time for the entry of new generation and the development of regulatory mechanisms to provide a

demand response. Even if the California IOUs are permitted, and/or encouraged, to develop balanced

supply portfolios with more long-term supplies, buying long-term now may reduce the volatility of their

supply costs, but it may not provide significant savings because current forward prices are high. Putting

a cap on these forward prices would allow time for the market to recover from the summer prices that

were unusually high because of a combination of factors. Choosing the correct level for this cap may be

difficult. If investors rely on forward prices, more than spot prices, to signal the need for new

investment, then finding the right long-term cap that will not discourage new investment may be a

delicate task. 

As an alternative to a price cap on long-term prices, the Commission could adopt

target prices for long-term contracts in the California market, based on pre-summer

prices. A less intrusive form of intervention would be to adopt some form of target price for forward

contracts for an 18-month period. The target price, or prices, would be voluntary but any wholesale

seller who sold too far above the target would be subject to investigation for the possibility of exercising

market power. If the Commission determined that a seller was exercising market power, the

Commission could rescind the market-based rates of the supplier.

One possible target price would based on the May 1, 2000, price for a standard six by sixteen

futures contract for July 2000 delivery at California's path 15 (either NP15 or SP15). The May 1,

2000, target price would have to be adjusted for any increase in natural gas prices and emissions

allowance credits since that date. May 1, 2000, might be a reasonable date upon which to base a

forward target price because the markets at that time were operating under relatively normal conditions
6-14

and prices for July 2000 delivery were consistent with prior periods, i.e., before market volatility

appeared. 

To implement this option the Commission may need to require monthly reporting of all

individual forward contracts offered (both accepted and rejected) by suppliers to monitor their behavior

during the transition period. The Commission could also encourage purchasers to report egregious

offers by power suppliers.

This option could be combined with a requirement for generators to offer a particular amount of

their supply in the forward market. However, there is no evidence that generators have been unwilling

to commit to forward contracts and much anecdotal evidence that generators generally desire the

financial stability provided by long-term contracts, at least for a portion of their supply. Therefore, this

kind of requirement may be unnecessary, in addition to being intrusive in the market.

The option of a target price on long-term bilateral transactions, can be combined with a price

cap on the spot market. Power suppliers with unsold generation from the bilateral market could have

an incentive to drive up prices in the spot market during times of scarcity in order to maximize their

revenue stream. 

The Commission can leave the spot market and long-term market prices

unconstrained. With the evidence of scarcity in the region, higher prices may be the correct market

response to stimulate needed new investment. The high prices seen recently in the forward market may

be the correct prices in light of the fact that shortages are likely to continue until 2002. Rather than

trying to dampen those prices, it may be more beneficial to the market in the long run to leave those

prices unconstrained. The experience in the Midwest after the price spikes in 1998 has been that

significant generation resources were added to the region in response to those high prices. This option

would be more effective if coupled with other actions to improve the overall functioning of the

wholesale market, such as measures to provide a demand response and to minimize the reliance on

spot market purchases. In addition, this option should be combined with increased monitoring of

market participants to detect evidence of market power abuse, with any such conduct penalized if

found.

The Commission can implement locational market power mitigation measures,

independent of the other options for price caps. A single supplier may exercise locational

market power because that supplier is the only option available to serve load in that area. The supplier

may have several generating units at that location with more than enough supply available to meet

demand; however, because of ownership concentration, the supplier can increase its price because of

market power rather than scarcity of supply. The instances of market power may be isolated and

infrequent, but this is an option available for mitigating the exercise of market power by a single

supplier. 
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 To mitigate the exercise of locational market power, the Commission could put in place

resource specific bid caps. When a generator is called upon for a locational need, the unit would be

paid either its bid cap if the market clearing price is lower, or the market clearing price if that price

exceeds the bid cap. In no event would the generator set the market clearing price. The Commission

could calculate the resource specific bid cap in several ways and let generator owners choose how they

will be compensated. The resource bid cap could take several forms: (1) the Commission could

require each generator to file the verifiable incremental operating cost which it would recover plus a

margin for some recovery of fixed costs; (2) the resource bid cap could be equal to the market clearing

price for similar hours and load levels when the unit's bid was in merit order with an adjustment for

changes in fuel prices and emissions credits; or (3) the resource bid cap could be an estimate for

running costs of a comparable unit. This option could be simplified to have one bid cap for each type of

generating facility (e.g., stand-alone combustion turbines, combined cycle units, oil or natural gas-fired

boilers).

This option is less intrusive than traditional cost-of-service regulation. It would be appropriate

if there are significant barriers to new entrants and those barriers are unlikely to be removed. If new

entry is possible, then an alternative would be to encourage other entrants into the market, and allowing

the prices to be high is a way to attract new entrants.

The Commission could change the auction rules used by the PX and the Cal-ISO

to pay sellers what they bid rather than the market-clearing price. Under this option the

auction rules would be changed to pay each seller its bid, rather than the market-clearing price, and

buyers would pay a price reflecting the average of the accepted sellers' bids. This might have the effect

of lowering the total paid by buyers during high demand periods because some sellers would be paid

less than the highest bid accepted. It may also change seller bidding behavior. Under this rule, sellers

might submit higher bids than they might under a market-clearing price rule because under this rule the

seller would only receive its bid, whereas under the market-clearing price rule, the seller would receive

the market-clearing price even if the seller bid less. If generator bidding behavior changes in this way, it

is not clear whether there would be much lowering of the total paid by buyers. Overall, it is not clear

what effect this rule change might have on the total paid by particular consumers since consumers

receive averaged monthly bills and not hourly bills.

5. Create a More Stable Regulatory Environment

The Commission can abolish the current stakeholder governing boards of the

Cal-ISO and the PX and require independent boards, non- stakeholder boards. This

would also eliminate the need for the EOB, which could be abolished also. The ISO and

PX stakeholder board structures are designed to preclude dominance by one or two voting classes, but

the stakeholder boards have difficulty coming to decisions on complex issues. These stakeholder

governing boards are charged with making very difficult decisions that require satisfying a complex of
8

 Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (January 6, 2000),

FERC Statutes and Regulations ¶ 31,089 at 31,046-48 (2000).

9

Id.

10Pacific Gas and Electric Company, et al., 81 FERC ¶ 61,122, slip op at 248-49.

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regulatory authorities, often under conflicting political and stakeholder pressures, while maintaining a

fiduciary responsibility to the ISO and PX. The stakeholder boards are more susceptible to influence

by the interests that they represent or by the direct or indirect pressures of others and are becoming

widely perceived as too easily influenced by local political pressure. 

As the Commission recognized in Order 2000, independence is the linchpin which should form

the basic foundation of an RTO and it should apply to all structures, including an ISO.8 The

Commission also reiterated that RTO governing boards have to satisfy the over-arching principle that

their decisionmaking should be independent of market participants.9 Recognizing that the Cal-ISO is

required to make its RTO filing by January 15, 2001, this may be the time to require a restructuring of

the ISO board from a stakeholder board to an independent board, with similar changes to the board

structure of the PX. Changing the structure of these boards could increase regulatory certainty in the

California market and bring some stability to the market. Eliminating the stakeholder boards would

eliminate the need for the Electricity Oversight Board. This would remove an additional source of local

pressure on these federally regulated entities and clarify the regulatory oversight of the wholesale

market.

The Commission can retain the sole authority to impose price caps in wholesale

market transactions and not delegate that authority to the Cal-ISO or the PX. The

repeated changes in the Cal-ISO price caps this past summer appeared to be the result of a highly

politicized decisionmaking process. This can be corrected by changing the board structure of the CalISO, but to provide more stability to the market, any wholesale price constraints that need to be

imposed should be imposed by the Commission. Only the Commission has the broad regional

perspective necessary to evaluate fully the value and impact of price caps on the market. 

Require the Cal-ISO and PX market monitors to report directly to the FERC any

evidence of market power abuse for evaluation and action by the Commission, without

prior review by their boards. The Cal-ISO and PX each have well established market monitoring

units and independent surveillance committees that monitor market behavior. The Commission could

require these entities to report any allegations and evidence of market power abuse directly to the

Commission. While these entities have the discretion to file their reports directly with the

Commission,10 the current board structure may hinder the release of information that the Commission

might find useful in its ongoing analysis of market behavior or that may be evidence of market power

abuse that needs corrective action by the Commission.
6-17

6. Other Options

To eliminate underscheduling in the Cal-ISO, the Commission can change the

incentives for suppliers to sell in real-time and can require stronger penalties for real

time purchases, combined with increased options for IOUs to have broader supply

portfolios. The underscheduling that has been experienced by the Cal-ISO causes reliability

problems for the ISO, so remedying this would appear to be important. It appears to be an outgrowth

of pricing policies that provide incentives for both sellers and purchasers to underschedule and then buy

in real time. To remedy this, the incentives need to be changed to give sellers an incentive to sell day

ahead or in forward markets, and to give buyers both the ability to minimize their purchasing costs with

the ability to forward contract and a disincentive to purchase in real time. For example, loads that

purchase real time energy could be required to pay a premium above the currently-calculated prices

and penalties for real time purchases. IOUs could also be allowed to purchase energy in forward

markets outside the PX. On the supply side, one way to encourage generators to offer more energy in

the forward markets would be to reduce the financial reward for providing replacement reserves. For

example, any payments to a generator for providing replacement reserves could be considered as a

down payment for any energy produced from the generator in real time. Thus, the price paid to the

generator for such real time energy would be reduced by the amount paid for providing the replacement

reserves. 

The Commission could direct a further investigation of generators with

abnormally high unplanned outage rates or bidders into the PX to examine whether

individual market participants may have engaged in withholding or price

manipulation. It may be appropriate for the Commission to take a more active role in investigating

and dealing with individual instances of market power abuse. For example, one way to physically

withhold capacity from the market is to contrive a forced outage. Of course, generation equipment will

break down from time to time even in a competitive market; so unexpected, forced outages will

naturally occur in any market. However, when a generator experiences an outage, capacity in the

market is reduced, and that tends to raise the market price. So a generator might be able to exercise

market power and raise the market price by contriving a forced outage, and thus, physically withholding

capacity. It may be difficult to determine whether a forced outage is legitimate or contrived. However,

when a generator's forced outage rate is abnormally high, especially during periods of tight capacity, it

may be useful to investigate the outage in more detail to determine whether it has been contrived as an

exercise of market power. If the outage is determined to be contrived, penalties could be imposed in

order to deter similar future behavior. 

In the time available for this investigation it was not possible to determine whether individual

market participants abused their market power. An option available to the Commission is to direct staff

to conduct a further investigation into individual conduct during the past summer. 
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With respect to future conduct, the Commission can revise its reporting requirements and

market monitoring methods to provide a more systematic basis for monitoring for instances of market

power abuse. Periodic market investigations, such as this investigation, are resource intensive efforts

for the Commission staff as well as the Cal-ISO, PX and the market participants, that do not provide

the kind of regular information collection needed to monitor the market and the behavior of individual

participants on a regular basis. For example, the Commission could require generators to report

unplanned outages to the Commission contemporaneously with the outage or soon thereafter. Although

the Cal-ISO and the PX have market monitoring staffs, they do not have the same authority as the

Commission to investigate individual behavior, and to take action against individual market participants.