Appendix — Pacific Gas & Electric Co. v. Public Utilities Commission

Supreme Court, U.S.

rit E ®

87-178 JUL 281987

No. JOSEPH F. SPANIOL, JR.

Fae BRK

In the Supreme Court

OF THE

United States

OCTOBER TERM, 1987

PaciFic GAS AND ELECTRIC COMPANY,

a California Corporation

Petitioner,

V.

PusBLic UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA,

Respondent.

APPENDIX TO

PETITION FOR WRIT OF CERTIORARI TO THE

CALIFORNIA SUPREME COURT

HOWARD V. GOLUB

ROBERT L. HARRIS

*LINDA L. AGERTER

P.O. Box 7442

77 Beale Street

San Francisco, California 94120

(415) 781-4211

*Counsel of Record for Petitioner

Pacific Gas and Electric Company

BOWNE OF SAN FRANCISCO. INC. + 190 NINTH ST. « S.F.. CA 94103 + (415) 864-2300

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TABLE OF CONTENTS

Title Pages

Order Denying Alternative Writ ................cccecee. A-1

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IID oan 6d one 540e0eKs ousensvecveaten A-126

I Gy cabs utdubrensvsiwssdanwer A-141

Ps ca cedcadekekbewessxtves es A-145

Decision No. 86-12-104 Certification of Mailing .......... A-149

Application for Rehearing of Decision No. 86-10-038 ...... A-168

Pacific Gas and Electric Co. Standard Offer No. 4—Power

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I ED ic ks crea cusesusecvsnsstvane A-247

PURPA, Section 210, 16 U.S.C. § 824a-3................ A-257

Analysis of Assembly Bills 1402 and 1403................ A-263

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APPENDIX A

Order Denying Alternative Writ

S.F. No. 25114

In the Supreme Court of the State of California

In Bank

Pacific Gas and Electric, Petitioner

v.

Public Utilities Commission, Respondent.

Panelli, J., Did Not Participate

[ Filed April 30, 1987]

Petition for Writ of Review DENIED.

/s/ Lucas

Chief Justice

A-2

APPENDIX B

Decision 83-09-054 September 7, 1983

BEFORE THE PUBLIC UTILITIES COMMISSION OF

THE STATE OF CALIFORNIA

Application 82-04-44 (Filed April 21, 1982; amended April 28,

1982, July 19, 1982, July 11, 1983 and August 2, 1983)

Second Application of PACIFIC GAS AND ELECTRIC

COMPANY for Approval of Certain Standard Offers Pursuant

to Decision No. 82-01-103 in Order Instituting Rulemaking

No. 2.

Application 82-04-46 (Filed April 21, 1982; amended May 12,

1982; July 11, 1983 and August 10, 1983)

In the Matter of the Application of SOUTHERN CALIFOR-

NIA EDISON COMPANY for an Order by the California

Public Utilities Commission Directing Edison to Purchase

Power from Qualifying Facilities Based on a Standard Offer for

Firm Capacity and Energy Based on Long-Run Marginal Costs

(OIR-2).

Application 82-04-47 (Filed April 21, 1982; amended July 11,

1983, and August 2, 1983)

In the Matter of the Application of SAN DIEGO GAS &

ELECTRIC COMPANY for an Order by the California Public

Utilities Commission Directing SDG&E to Purchase Power

from Qualifying Facilities Based on Standard Offers and to

Make Certain Changes or Additions to its Tariffs Affecting

Purchases from Qualifying Facilities.

(For appearances see Appendix A.)

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INTERIM OPINION

These proceedings involve adopting standard offers based on

long-run avoided costs for power purchase contracts between the

three largest electric utilities and qualifying facilities (QF). The

utilities are: Pacific Gas and Electric Company (PG&E), South-

ern California Edison Company (SCE), and San Diego Gas and

Electric Company (SDG&E).

Before explaining the procedural history which has brought us

to this point, we think it is constructive to explain briefly why we

have pursued developing such standard offers in view of the

standard offers in-place which pay QFs for their power based on

actual short-run utility avoided costs.

I. SUMMARY OF DECISION

This decision authorizes what is termed Standard Offer #4,

which has different payment options for QFs, all of which are

based on forecasts of the utilities’ resource mix and costs. The

three payment options under Standard Offer #4 resulted from

negotiations. A negotiating conference, which lasted five weeks,

was held at our direction, with vigorous participation by utilities,

QFs, and our staff. We have committed to hold evidentiary

hearings, which almost all parties desire. However, there is

substantial agreement among utilities, QFs, and our staff that

until a more permanent solution is found for the complex task of

fairly valuing and pricing QF power over the long-run, Standard

Offer #4, with three payment options, should go into effect.

We undertook the negotiating conference in the hope of com-

ing closer to an interim solution which, while not perfect from all

perspectives, could be useful for QFs and utilities. While some

may have hoped to accomplish more than the scope of the

consensus reached, or they would have preferred different results,

we think the negotiating conference was extremely fruitful.

The negotiated standard offer and three payment options are

approved, with some reasonable restrictions on their use set by us

under our prerogative.

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Standard Offer #4, at this juncture, is interim in the sense it

may ultimately be replaced with a different costing methodology,

contract terms, etc. However, until that happens, it may be fully

relied on by utilities and QFs who find the options useful. Those

who contract under interim Standard Offer #4 will not be subject

to having terms or prices changed later, except as narrowly and

specifically ordered by this decision. Any changes made to this

standard offer in the future will only apply to those contracting

after such changes. Potential QFs who find they cannot use

Standard Offer #4, as approved today, still have the option of

pursuing a negotiated nonstandard contract with utilities.

Il. BACKGROUND

Utilities’ short-run avoided costs have proven to be more

volatile than many observers would have guessed. We have seen a

drastic run-up in fuel oil and gas prices, followed by a moderate

decline in oil prices. The QF industry contends that the price

uncertainty posed under the existing as-available and firm capac-

ity standard offers, both based on short-run avoided costs, makes

it extremely difficult to arrange financing for potential QF

projects. QFs tell us that those who hold the financing purse-

strings, both lenders and equity investors, are reluctant to commit

captial when a project’s payment stream is so uncertain. Our

Decision (D.) 82-01-103 in OIR 2, issued January 21, 1982,

recognized the need to pursue developing standard offers based on

long-run avoided utility costs (page 67, mimeo.). Oil and gas

prices were steadily rising when that decision was issued, and

although the three largest electric utilities were ordered to file

applications with proposed standard offers based on long-run

avoided costs, most of our attention and that of the QF industry

was directed to perfecting standard offers based on short-run

avoided costs. Many assumed oil prices would continue to rise;

few seemed to believe they would start a decline. As oil prices

started to decline the intensity of interest in standard offers which

would produce prices based on long-run (and presumably less

volatile) avoided costs correspondingly increased.

If we do not adopt a standard offer based on long-run avoided

costs as an alternative to the existing standard offers, the pressure

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for nonstandard contracts between utilities and QFs could steadily

increase. Such nonstandard contract negotiations pose problems

for all: QFs typically ask for variations of up-front price security

or certainty so they can finance projects, and utilities are faced

with ensuring the nonstandard contract has suitable terms to

make it a secure venture for them and their ratepayers; further,

operating under our regulation, utilities are concerned about

ultimate cost recovery, and worry that the prudence of nonstan-

dard contracts may be successfully challeged in their energy cost

recovery proceedings. Also, the long-term value of new QF

capacity in the utilities’ resource plans is not fully reflected by the

existing standard offers which base prices on fluctuating short-run

avoided utility cost (see D.82-01-103, p 67). It is, then, in

everyone’s interest that a standard offer based on long-run

avoided cost be adopted.

The threshold problem is how can long-run avoided costs be

determined. Dealing with short-run avoided costs was difficult,

but the problems were surmounted and standard offers are in

place. However, to value QF power reasonably in the long run, we

must make many assumptions about the utilities’ future genera-

tion mix and costs. While we deal extensively with forecasting the

future when ratemaking, the view is only 1-3 years. This does not

mean we cannot project the value of QF power for longer periods,

say 10-15 years; but it means that the method used to forecast the

value of QF power must be one that is not biased at the outset

with a likelihood of being too high or too low when, after the test

of time, payments to QFs under the forecast are compared to

actual avoided costs. Or, from the ratepayer’s perspective, there

must be an even chance that the forecast will be too high as too

low.

There are different ways of arriving at estimates of long-run

avoided costs, and the future value of QF power, but all involve

proxies or the creation of a utility’s generation mix and costs on a

composite basis viewed at some future time. The “generation

resource plan” approach, for example, would evaluate the

(weighted) capacity and energy costs associated with the utility’s

projected mix of resource additions without the availability of QF

power. Some (not the utilities) prefer using a coal plant as the

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assumed resource addition that would be deferred by long-term

QF power. Another method, discussed later in this opinion, is

forecasting short-run avoided costs into the future to capture a

proxy of future conditions. Under this approach, the value of QF

power is computed on the general assumption that the utility does

not make any new plant investments except in some short run

peaking capacity to maintain system reliability. Once this value is

quantified then various options for paying QFs for their value are

applied. Obviously, the longer the forecast the more problematical

it is to rely on for valuing QF power and paying QFs, in that we

are committed to treating the prices paid under the standard

office as per se reasonable, to be passed on to ratepayers.

Some may contend that prices fixed under long-term forecasts

can, at least at times, be above actual avoided costs, and therefore

both: (1) PURPA will be violated in that payments will exceed

avoided costs, and (2) the ratepayers will pay too much. We think

the proper view and test is whether over the course of a long-term

contract, despite periodic swings in actual avoided costs both

above and below a forecast, the prices reasonably compensate

QFs for their value in avoiding a utility’s costs, and keep the

ratepayer economically indifferent to whether the generation was

performed by the utility or a QF. As long as there is equal

likelihood that swings in actual avoided costs are both below and

above the forecast, over the term of forecast based prices, we

think the spirit and letter of PURPA are followed.

More troublesome, perhaps, for some is that we are adopting

long-term standard offers based on forecasts of escalating avoided

utility costs when there is no current capacity shortage among

California utilities. The question becomes: why stimulate QF

projects which cannot now proceed in the generation marketplace,

under the existing as-available or firm capacity offers based on

short-run costs, by adopting offers based on long-run utility

avoided costs? The answer is that standard offers based on long-

run avoided costs are for long-term contract commitments. We

would rather err on the side of trying to have QF capacity steadily

come on line over time, than on that of ultimately risking a

critical capacity shortage because we did not take reasonable

steps to afford an opportunity for QF power, particularly long-

A-7

term capacity, to be steadily developed. Many of the QF projects

that may materialize because of the standard offers we adopt

today may not come on line for several years. Also, developing QF

power means California will be better able to meet its power

needs from within its borders, and the State’s resources will be

more fully and efficiently used. Finally, we have never said that

QF power must be developed at any cost, but rather that it should

be developed with reasonable cost to ratepayers when viewed in

the longer-term perspective. In the long run, if we do a reasonable

job of valuing and pricing QF power, the ratepayers should be

indifferent as to whether eventually needed capacity is supplied by

QFs or electric utilities.

Ill. PROCEDURAL HISTORY

A. General

A first prehearing conference was held on July 19, 1982 before

Administrative Law Judge (ALJ) Myers. Although hearings

were not scheduled, procedural issues were raised. On November

18, 1982 we issued a report on the general issued involved in

devising standard offers based on long-run avoided costs, and

requested comments. We did this primarily to stimulate thinking

among the parties on these issues, and to see if there was any

consensus on the very tentative conclusions we had reached at

that time. Eighteen parties filed comments. Then, on May 4, 1983

we issued D.83-05-038, which set a negotiating conference start-

ing on May 23 at Hastings College of the Law. It was our hope

that with good faith negotiations between the utilities, QF inter-

ests, our staff, and other interested parties, some tentative agree-

ment could be reached about a standard offer(s); any agreed

upon standard offer would, of course, require our ratification.

The ground rules of the negotiating conference were that any

standard offers to be proposed to us for consideration should be

completely worked out i1 final form, and that the assent of all

interests at the negotiating conference was required before a

standard offer would be proposed; this was essential to protect the

rights of all parties since there were no evidentiary hearings. The

goal, among the parties, was to attempt to develop an interim

standard offer which, while not perhaps the perfect preferred

A-8

solution from their individual perspectives, would be one which

they could comfortably tolerate and work under while refinement

and “perfection” could be pursued in subsequent evidentiary

hearings. Their understanding, based on our procedural plans as

communicated by our ALJ, was that if we approved an agreed

upon standard offer it would be an interim measure, subject only

to change prospectively after formal hearings. It was also under-

stood that the “final” Standard Offer #4 resulting from eviden-

tiary hearings could, if appropriate after further evaluation, be

based on an avoided cost methodology and/or pricing structure

that differs from the interim order.

The negotiating conference concluded on June 24, 1983. The

ALJ directed the three utilities to amend their respective applica-

tions no later than July 11, 1983; their amendments would contain

proposed standard offers, complete with contract language, that

precisely reflected the consensus agreement reached at the nego-

tiating conference. The ALJ then set a second prehearing confer-

ence on Friday, July 22, 1983 to allow parties an opportunity to

indicate whether the proposed standard offers should be allowed

to go into effect by this Commission pending evidentiary hearings

on the multitude of issues surrounding pricing QF power. Again,

parties understood throughout the negotiating conference that if it

produced some “negotiated” standard offers, which the Commis-

sion subsequently approved, they would be afforded an opportu-

nity through the hearing process to propose modifications for

prospective applications.

B. The Negotiating Conference Process

This was the first negotiating conference formally arranged and

hosted by us. In some respects it is a frustrating process, because

consensus building in a relatively unstructured arena (as com-

pared to our hearing process) can be cumbersome. On the other

hand, particularly if time limits are set, some consensus can be

reached relatively quickly, whereas adversarial hearings on such a

complex subject with a polarity of positions can take months

longer. This is not to say the negotiating conference was

nonadversarial; we understand it was adversarial. In fact, a critical

ingredient of this process is that all sides are represented with

near-equal resources and clout.

A-9

We were fortunate to have our staff coordinated and repre-

sented by the Director of the Utilities Division. We would be

greatly concerned if our staff had not been an aggressive and key

negotiating party, for it would raise the specter of utilities perhaps

ultimately reaching the point with QFs of saying, in effect: your

proposals do not sound fair, but since our cost recovery is virtually

guaranteed if prices are paid under Commission ratified standard

offers, what do we care-—-we will go along. However, neither

consensus resolution of issues nor routinely seeking to split the

difference, necessarily guarantees the best resolution from the

standpoint of the public interest, which is why we must be

guarded and very selective in deciding when to use the negotiating

conference procedure, and in evaluating its results. We note from

the prehearing conference that some QF representatives seem to

feel that too much emphasis is placed on whether our staff, as a

participant in negotiations, agrees on how an issue is resolved.

Vigorous staff participation is an essential ingredient in any arena,

and if some parties find staffs direct participation troublesome, it

is probably a good indication our staff is doing the aggressive and

thorough job we expect.

The most critical aspect of this process is that each agreed upon

standard offer resulting from the negotiating conference is

presented to us on a take-it-or-leave-it basis. Each was truly

negotiated as a “package”, comprised of cost forecasts, prices,

and contract terms, etc. We are, at this juncture, without an

evidentiary record upon which to weigh various proposals and

adopt a standard offer reflecting a careful weighing of various

components. Essentially, then, we face either accepting or re-

jecting each of the three standard offer payment options as

negotiated, and we do not, in fairness to the parties, have the

latitude to make modifications.

C. The Second Prehearing Conference

At the second prehearing conference on July 22, 1983 a

number of QFs indicated that while there was substantial agree-

ment that two of the payment options under Standard Offer #4

were complete and acceptable, there were serious reservations

remaining with respect to:

A-10

1. Option #3, or the forecasted incremental energy rate

option, as filed by PG&E and SDG&E; they found Edison’s

acceptable because they liked Edison’s forecast.

2. Option #4, filed by PG&E only, which is a forecasted

energy floor price payment option. This was an option not

fully developed or addressed during the negotiating

conference.

QFs, essentially, asked that the negotiating conference be

resumed or that they be allowed to pursue ad hoc negotiations

with utilities. They stated a preference not to pursue refining

Options #1 and #2 until ail issues, from their perspective,

relating to all four payment options are resolved. Also, they

expressed the opinion that the “Regulatory Authority” clause in

Edison’s and SDG&E’s proposed standard offer must be elimi-

nated, and the issue about contract switching must be resolved.

After conferring with the assigned Commissioner, the ALJ

ruled that the prehearing conference would be continued to

August 8, 1983, for the specific purpose of allowing utilities to

address concerns QFs has about contract language pertaining to

Options #1 and #2. Also, he announced that the QFs’ request to

reopen the negotiating conference would be addressed by the

Commission in this decision. QF representatives then listed the

particular contract language and areas which, from their perspec-

tive, needed nonsubstantive changes so the contracts, mechani-

cally, conformed to the agreement reached at the negotiating

conference. Given the list of specified contract language “problem

areas”, the ALJ directed the utilities to review their contract

language with QFs and staff, and to distribute any revised page

before the prehearing conference continued. They were directed

not to “negotiate”, but, rather, to work together to ensure that the

contract language is clear and carries out the intent of the

negotiated settlement. The ALJ announced that the Commission

would address the interrelated issues of contract switching and the

contracts’ regulatory authority clause in its decision; those issues

are discussed later in this opinion.

On August 8 the prehearing conference resumed. An opportu-

nity was extended to all parties to address whether the proposed

|

A-11

Standard Offer #4 payment options should go into effect, whether

evidentiary hearings should be held and, if so, what issues should

be addressed. There was an array of positions on these matters, as

well as on whether the negotiating conference should be

reopened.

Edison and SDG&E think the three payment options proposed

with Standard Offer #4 should go into effect, and that before

hearings are held the reaction and experience under those pay-

ment options should be studied and evaluated. Neither utility

proposed a floor price mechanism as PG&E did, and they think

such a conceptual payment option needs considerable study.

PG&E thinks all four of its proposed payment options should go

into effect, and it too thinks we should hold off going to hearing

until we gain some marketplace experience with interim Standard

Officer [sic] #4. While some QFs think further negotiations on

PG&E’s incremental energy rate forecast would be fruitful (e.g.,

result in a more favorable forecast), PG&E indicates further

negotiations would be futile (PHC transcript, page 156). Edison

indicates that at some point the entire areas of costing methodol-

ogy, payment stream options and, more narrowly security provi-

sions for contracts, should be scrutinized in hearings.

Our staff thinks all the payment options, except the floor price

mechanism proposed by PG&E, should go into effect on an

interim basis. The floor price mechanism warrants thorough

review from the standpoint of ensuring ratepayer economic indif-

ference and protection, and staff believes some “workshop” forum

in conjunction with or before evidentiary hearings might be

fruitful. Staff is not convinced that this particular payment option

can be quickly resolved by negotiations. Staff believes that further

efforts at negotiating the incremental energy rate forecast of

SDG&E and PG&E so they are acceptable to more QFs would

probably not be fruitful. Staff thinks at this juncture the entire

subject of costing methodology, valuing long-term QF power, and

pricing streams should be the subject of evidentiary hearings.

The California Energy Commission and the State Solid Waste

Management Board both want us to direct further negotiations

aimed specifically at having SDG&E and PG&E develop incre-

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mental energy rate forecasts more favorable to QFs, and adopting

a floor price mechanism payment option.

None of the QF representatives who made statements at the

prehearing conference had any objection to Payment Options #1

and #2 going into effect for all three utilities. They all thought

Edison’s Option #3 was acceptable, because they prefer Edison’s

incremental energy rate forecast over that of either SDG&E or

PG&E. Contrary to the views of PG&E, SDG&E and Staff, QFs

almost uniformly believe if we direct more negotiations on the

incremental energy rate forecasts of PG&E and SDG&E the end

result will be more favorable forecasts. We note at this juncture

that if we ordered more negotiations on the incremental energy

rate forecasts of only two of the three utilities, our action would be

taken as a strong signal that we have reason to believe their

forecasts are too unfavorable to QFs. We have no facts or

evidence to lead us to such a presumption; all we know is that

some QFs say they need and would prefer more favorable fore-

casts. QFs all seem to indicate that if we do not order further

negotiations aimed at these forecasts, then we should authorize

the incremental energy rate forecast payment option as proposed

by SDG&E and PG&E because some QFs may be able to use

those payment options.

QFs think the latest floor price mechanism payment option

proposed by PG&E is acceptable, and that if we do not totally

approve it, and direct the other utilities to include it in their

respective standard offers, then we should at least clearly embrace

the concept and direct it to be the subject of further negotiations.

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Other points raised by some QF representatives are:

1. We ought to clarify whether utilities can still pursue

nonstandard contracts with potential QFs who do not find

one of the standard offers use ful.

2. The question of whether QFs already under contract

may switch to Standard Offer #4 should be addressed and

resolved, preferably with the result being freedom to switch;

and, likewise, whether subsequent versions of Standard Offer

#4 that may result after hearings should then be freely

available retroactively to QFs who signed a contract under

negotiated Standard Offer #4.

Both issues are addressed later in this opinion.

Some QFs want evidentiary hearings, primarily to develop a

permanent costing methodology for valuing long-term QF power,

to resolve the need for security provisions in contracts, and to

pursue adopting methodologies and/or forecasts that are readily

verifiable. On this latter point, one goal almost all QFs share is

having utilities use a common forecast of long-run marginal costs

for pricing QF power and for utility resource planning purposes.

This, they say, would result in QFs no longer being “whipsawed”’

by utilities, which are the ultimate data repositories, using differ-

ent forecasts for different purposes.

IV. LIMITATIONS ON THE AVAILABILITY OF THE

ADOPTED STANDARD OFFER AND CONTRACT

SWITCHING

The standard offers we have already adopted are based on

utilities’ short-run avoided costs, and they set prices which can

fluctuate, but which closely parallel actual avoided costs. How-

ever, the standard offer addressed by this opinion involve projec-

tions, assumed proxies, and payment stream certainty which can

have a visible impact on electric bills. This standard offer is the

first with such characteristics, and there will undoubtedly be

refinements and modifications adopted, for prospective applica-

tion, as time goes by and experience is gained.

We will adopt some overali limitations on the use of this

interim standard offer in recognition that we are not convinced

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that it is a permanent all-inclusive solution. Parties agreed, at the

negotiating conference, to recommend that the negotiated stan-

dard offer be allowed to remain in effect at least six months, but

no more than two years. It will probably be at least six months

before hearings conclude, so we have no difficulty ordering the

offers ratified by this decision to be in effect for at least six

months, and until further order.

SDG&E requests that its forecast of marginal operating costs

underlying its energy prices be used for a maximum of six

months; that issue will be addressed later in this opinion.

Am important point for our resolution is whether existing QFs,

already in production and under contract, should be eligible for

the standard offer adopted in this decision. At the negotiating

conference the utilities asked for some clarification, wanting to

avoid a morass of uncertainty and contract administration

problems. None of the participants had specific suggestions at the

negotiating conference, but all seemed to want some clarity. ALJ

Alderson promised to bring the matter to the Commission’s

attention for resolution.

In the past, when the entire subject of devising standard offers

was in its infancy and the existing standard offers based on short-

run avoided costs were evolving, we allowed QFs under contract

to switch to the standard offer based on short-run costs which

ultimately evolved (D.82-01-103, mimeo page 145); subsequently

we said: “QFs may not switch from one standard offer to another,

but may adopt the final version of the particular offer signed”

(D.82-12-120, issued December 30, 1982, in A.82-03-26 et al..

mimeo page 118).

We think there are overall problems with contract switching,

and the preferred approach in this instance, particularly since the

standard offer before us is so fully developed with all contract

terms and complete with fixed prices, is for QFs to evaluate it

from the basis of making a long-term commitment, for a 15-year

minimum term is involved. Accordingly, QFs who sign up under

one of the options under this standard offer, albiet interim in one

sense, will not be allowed to switch later; they must wait until the

end of their contract term.

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With respect to QFs already in production, we will allow them

to sign up under this standard offer only if they are no longer

under contract; QFs who have decided to produce under existing

standard offers, and who entered a contract, should be bound by

their decision.

Some standard and nonstandard contracts have provisions

which allow QFs to elect standard offers which may be approved

subsequent to their entering the nonstandard contract. However,

the standard offer approved by this decision represents only an

interim solution, subject to change after hearings, for prospective

application. As such, since we are adopting a standard offer

without an evidentiary record, we are not comfortable allowing

QFs under contract, even nonstandard contracts, the switch. QFs

under standard and nonstandard contracts, with provisions clearly

allowing them to switch, may switch after a final standard offer

comes into existence after hearing, but for the time being they

will have to honor their commitment under the contracts they

entered. A critical factor in our thinking is that this standard offer,

and the procedures leading to it, resulted primarily from our goal

to encourage new QF projects which have not yet obtained

financing or otherwise entered a contract and started production.

Finally, we will limit the levelization payment option under this

standard offer to new QF facilities or those which have never

produced and sold power. This is because, with some reluctance,

we approve the levelization option as a stimulus for new QF

projects, and it is not reasonable for ratepayers to bear the cost of

levelization in the early years to benefit a QF project or facility

which has already managed to obtain financing and start

production.

A subject so closely related to contract availability and switch-

ing warrants discussion at this point, is our concern about QFs

breaching, or otherwise altering the contracts entered under

Standard Offer #4.

PG&E’s amended application summarizes the overall underly-

ing concern about fixing QF payments based on a forecast or, for

that matter, any proxy of anticipated utility avoided costs:

A-16

“We can be certain that actual avoided costs will differ from

the forecasts. Locking into a forecast in a rigid way assures

that there will be economic losers—either QFs or ratepay-

ers—in the future, because actual avoided costs will either be

above or below the forecast. Staff believes that a disadvan-

taged party won’t mind, because there had been an equal

chance of being the economic ‘winner’ at the time the

contract was executed. This is good theory, but it defies

experience. If one party is seriously disadvantaged by a

contract, it will have strong motivation to breach or alter the

contract, regardless of how reasonable the contract appeared

when it was signed.

“Similarly, PGandE expects that if QFs are disadvantaged

by the forecast price options, they will do everything possible

to renegotiate, terminate, or otherwise escape their obliga-

tions. We have attempted to write the contract to avoid this,

but with the amount of money potentially at stake, ways may

be found. Conversely, if ratepayers are harmed, we expect

accusing fingers to be pointed at PGandE and at the Com-

mission. We trust a future commission would abide by a

decision of this one and allow costs to be recovered.”

(PG&E amended application, Exhibit A, page 4).

We think, QFs may be “winners” at times and “losers” at

others, when, at any point in time, originally forecasted avoided

costs are compared to actual. However, the recent volatility in

short term utility avoided costs caused by oil price fluctuations

will probably be borne in mind by QFs electing one of the forecast

based payment options under Standard Offer #4. Accordingly, we

believe they will think long and hard before seriously attempting

to terminate early or to breach their contract. However, we agree

with PG&E that some QFs under long term Standard Offer #4

contracts may seek to get out of those contracts if actual avoided

cost conditions, particularly over a fairly long duration, would be

to their advantage (despite the potential for damages generally

A-17

and specific minimum damages clauses in some of the

contracts).'

We think it is reasonable to order that utilities are under no

obligation to enter into any power purchase contract, even under

one of the otherwise available Commission approved standard

offers, with a QF who has terminated early or breached under

Standard Offer #4, payment options approved by this decision, if

damages have not been collected. By damages we mean the utility

either having collected at least the minimum damages, if the

contract has a minimum damages clause, and foreseeable dam-

ages if their is no applicable minimum damages clause. Parties

should honor their contractual commitments, and we think our

making it unattractive for QFs to terminate or switch contracts is

only fair, as it balances the risk ratepayers are assuming at the

Outset with this long-term, forecast based, fixed price, standard

offer. While this issue was not specifically raised at the negotiat-

ing conference, we think it is our prerogative to take reasonable

steps to minimize contract evasion; indeed, under the circum-

stances it is our duty to the ratepayers.

V. THE STRUCTURE OF STANDARD OFFER #4 AND

FUTURE CONTRACT LANGUAGE CONSISTENCY

This opinion will address what is called Standard Offer #4,

which contains several payment options. Standard Offer #1 was

adopted by D.82-12-120, and is for as-available energy payments;

#2 is for firm capacity, and #3 is for smaller QF projects (under

100 kW). The Standard Offer #4 contracts proposed by each of

the three utilities has some common contract terms that apply for

all options, and specific terms covering the individual payment

options. The filed contracts are complete with the agreed upon

forecasts, upon which prices will be paid.

Each utility chose its own format and contract language, with

the goal, however, of all being consistent in substance (with the

' Minimum damages clauses apply to capacity payments when the

firm capacity option is selected for capacity payments, and for energy

payments when a levelized payment option is selected. Aside from the

minimum damages clauses, utilities may pursue foreseeable damages as

apply in any breach of contract situation.

A-18

exception of certain agreed to utility specific terms, such as

curtailment). As experience is gained with standard offers, and

QF power purchase contracts generally, uniform standard con-

tract language should be used by all utilities, except for terms

which must clearly be utility specific because of substantitive

differences. The convenience of standard language will greatly aid

those who must review standard offers. We are disappointed this

could not have been done for Standard Offer #4 in the context of

the negotiating conference, but it appears time did not permit it.

Rather than to simply pick one of the utilities’ contracts and order

that language used by the others, we will direct the utilities to

work together, with our staff, in proposing one form of Standard

Offer #4 with uniform language (except where terms must be

utility specific). Six months will be allowed for this undertaking,

and the product shall be presented during the subsequent hearings

for review.

That, we think, is adequate time for the three utilities’ and our

staff to harmoniously come to some common terms. QFs will

have an opportunity to address the uniform Standard Offer in

subsequent hearings. Once adopted standard offers are uniform

for all utilities, it will be far easier to review and consider proposed

changes, and to subsequently review any filed standard offer

contracts in the future for compliance with Commission direc-

tives. As it now stands, for example, we, our staff, and interested

parties, must review three very thick contracts and engage in

cumbersome, confusing and time consuming cross-checking. We

think consistency would be an enlightened step which, in the long

run, will work to everyone’s advantage.

VI. RAMPED-UP AND LEVELIZED LONG-TERM EN-

ERGY AND CAPACITY PAYMENT OPTIONS

UNDER STANDARD OFFER #4 (OPTIONS #1 AND

#2)

Two energy payment options under the standard offer were

proposed which warrant separate discussion because they share

the same costing methodology, but have different payment

streams.

A-19

Option #1: Payment stream fixed for 10 years,’ and

follows a ramped-up forecast.

Option #2: Payment stream fixed for 10 years and

levelized.?

A. Common Elements:

Before addressing the specific differences, (primarily the issue

of security), we will describe the common elements.

Contract term: The minimum term is 15 years, and the

maximum is 30 years (Utilities should amend their contracts to

specify the agreed upon maximum term).

Operation date. The QF project must be on line within 5

years from the date the agreement is executed. However, the QF

agrees to the payment stream, based on the forecast, when the

contract is signed. This means utilities must have a 15-year

forecast when the contract is signed to allow for a maximum 5-

year hiatus before operation and payments start after contract

execution. QFs can, however, under the negotiated standard offer,

make an election within ninety days before production starts on

whether they will be paid under the ramped-up or levelized

forecast. Thus, while both payment streams are known and fixed

when the QF signs a contract, a QF can hold off with its final

payment stream election and evaluate its requirements and condi-

tions shortly before production begins.

Forecasts Underlying Contract Prices: The total utility

avoided cost underiying the payment streams is technically com-

posed of two elements: (1) avoided shortage costs, related to the

peaking capacity the utility can avoid (based on the rental value

of a combustion turbine), and; (2) system marginal operating

costs, called the “energy” portion of the total avoided cost.’ The

> Ten years if the contract term is 20 years or more, but % of the

contract term if the total contract term is less than 20 years.

>The appropriate standard for evaluating future utility and QF

projects is a forecast of utility’s marginal energy cost plus shortage cost.

This is only a proxy for a forecast of average marginal composite energy

cost and capacity cost. The shortgage cost is not literally the “capacity”

A-20

forecasts accompanying the filed standard offers were agreed to at

the negotiating conference; while some may think they are too

high, and others that they are too low, nevertheless they were

agreed to. Whether the forecasts should be revised, for prospec-

tive application to new contracts, can be addressed in the subse-

quent hearings. The following schedules show the forecast energy

portion of the total avoided cost for each utility. For illustrative

purposes, the table for PG&E shows the price by time of delivery

as well as the annual average price, only the annual average prices

for Edison and SDG&E are shown:

Pacific Gas and Electric Company

Forecasted Energy Price Schedule

Forecasted Energy Prices*, ¢/kWh

Year of Period A (Winter) Period B (Summer)

Energy On- Partial- Off- On- Partial- Off- Annual

Deliveries Peak Peak Peak Peak Peak Peak Average

NE 5.36 5.12 4.94 5.44 5.31 5.19 5.18

SN 6 Gie x's 44 5.66 5.40 5.22 5.74 5.61 5.48 5.47

Acca Kas 5.75 5.48 5.30 5.83 5.69 5.56 5.55

araer 5.99 5.72 5.52 6.08 5.94 5.80 5.79

ee as Deh ues 6.38 6.08 5.88 6.47 6.32 6.17 6.18

_ ES 6.94 6.62 6.39 7.03 6.87 6.7) 6.70

RP eee 7.60 7.25 7.00 7.70 7.53 7.35 7.34

NS ia ate 8.12 7.74 7.48 8.23 8.04 7.85 7.84

SEs Vase os 8.64 8.24 7.96 8.75 8.56 8.35 8.34

ES wainia'e nie 9.33 8.90 8.60 9.46 9.24 9.02 9.01

Sa 10.10 9.63 936 10.23 10.00 9.76 9.75

eS . 10.91 10.41 1006 1106 1081 10.55 10.54

PCS ee 11.79 11.25 10.87 11.96 11.68 11.40 11.39

ee 12.67 12.009 11.68 12.85 12.56 12.25 12.24

SR ie 13.61 12.98 12.54 13.79 13.48 13.15 13.14

* These prices are differentiated by the time periods as defined in

PG&E’s standard offer, the time periods are subject to change

in accord with how peak, partial peak, and off peak is defined in

payment nor is the system marginal operating cost the “energy” cost,

but that terminology has evolved into this long-run standard offer

proceeding from the short-run standard offer proceedings. This is one

complexity among many relating to avoided cost forecasting that will be

addressed in the evidentiary hearings.

A-21

PG&E’s tariff schedules applicable to large industrial

customers.

PG&E, Edison, and SDG&E

Forecasted Energy Price Schedule, Annual Average

(¢/kWh)

Year PG&E Edison SDG&E

die is bk Sakae pant et ee 5.18 5.30 a

I rs Gch alae ent 5.47 5.60 5.90

eis 65s cae ciate ied me 5.55 5.70 6.40

as ead eae sai hae oo 5.79 6.00 6.40

EN fe oe rena yak ces 6.16 6.40 6.30

Sad le au Six Oe bak wk ok be 6.70 6.90 6.70

a hss x60 5 ead tales 7.34 7.69 7.90

SR DOERR IIE RD Ore ee 7.84 8.10 8.60

Ss ys bas ove ks ee aware 8.34 8.60 9.20

PG Sia) bani ehhaleeb et 9.61 9.30 10.00

pe ra Dapper eases Senne 9.75 10.10 10.30

rye sete bias odes wit 10.54 10.90 11.10

PEAS nee ee ee 11.39 11.80 11.80

tS oe er Ae 12.24 12.60 12.60

er Se tee a ans 13.14 13.60 13.40

aE Pan ener ga rr iy Eee — — 14.20

The preceding schedules show the 15-year forecasts of avoided

marginal energy costs, which is, of course, one component of total

avoided costs.

In understanding how total contract prices are derived, it is

critical to keep in mind there are a number of mix-and-match

options for both energy and shortage cost or capacity payments.

For example, a QF can elect to sell part of its output under the

terms of one of the existing standard offers based on short-run

avoided costs; if he did so, the energy sold under short-run as

available or firm capacity standard offers. would be subject to

price variation, whereas the portion sold under the forecast would

have a fixed price. Also, different shortage cost or capacity

payment options are available to QFs signing up under any of the

energy payment options.

A-22

Capacity payment price: QFs may elect to deliver either firm

or as-delivered capacity. The QF can select how much firm

capacity he will be contracted to provide, and any excess deliv-

eries will receive the as-delivered capacity price. These capacity

payments are determined and paid under the same terms as those

in existing Standard Offers #1 an #2, for as-available and firm

capacity, respectively. Thus, firm capacity payments can be

levelized as provided by Standard Offer #2, and are subject to the

performance bonus when the QF demonstrates a firm capacity

factor in excess of 85%; all capacity payments are made monthly.

The following table shows the annual average capacity payment

in ¢/kWh for as-available capacity:

PG&E, Edison and SDG&E

Forecasted Capacity Price Schedule, Annual Average*

(¢kWh)

Year PG&E Edison SDG&E

SRS vir rere Cee ree RS 798 .199 —

Ss Sx CA SE Maa a es oT eee enes .867 .868 .700

EERE OEY OLE PERE Ee Se ere 924 924 740

PE academe eed bak eae AN e RRS 1.004 .993 .800

Neo hikca ty a ee me ON ee Coe 1.084 1.073 .870

Dek CRA ean coe enews 1.164 1.153 950

PE eT Sasa ak eho b UE MEU Sa oe .255 1.244 1.020

PEROT Oe a ee yer Pere ie err a en 1.346 1.335 1.100

Cg A ee ee res Sere were ee 1.438 1.439 1.310

ESS ke he eA A he nie aed 1.541 1.690 i.400

kek by dy ee eae Oa kee eee 1.643 1.804 1.500

MELLO EE EE CORE PPLE eer ee 1.757 Le 1.600

ae Ran Gue Kaan de hae en em kn 1.871 2.055 1.720

cs ch ek aes fio oeae eres 2.009 2.215 1.840

Wi ue ho Weg vO Ghee sao EO 2.146 2.352 1.960

hg, AE OTe CEO EE TE ee — — 2.100

* For payment purposes the annual average rate will be converted

to seasonal Itime [sic] of delivery rates consistent with the

Commission approved method applicable to as-available capac-

ity. The annual average rate expressed in ¢/kWh, rather then

$/kWh, is developed for the utilities’ capacity payment fore-

A-23

casts, applying their allocation factors and hours per period

currently in use.

B. Forecasted Ramped-Up Payments Based on Energy or Sys-

tem Marginal Operating Costs (Option #1)

Option #1 is the ramped-up payment stream, with the payment

varying with season and time of delivery. This provides a direct

price signal to encourage peak period delivery by QFs.

During the fixed price period, (maximum 10 years) the QF

receives a series of predetermined energy prices for production,

broken down by year and costing periods. These fixed prices per

kWh are paid regardless of whether the utility’s actual avoided

costs turn out to be higher or lower. QFs can choose to take a

fraction (in 20% increments) of their energy payments under this

option, and the remainder under the full short-run avoided costs

applicable under Standard Offers #1 and #2. Oil or gas-fired

cogeneration facilities are limited to receiving no more than 20%

of their energy payments under the forecasted energy price option,

with the remainder paid at the full short-run avoided operating

costs under other existing standard offers, or under Option #3

(which is described later).

After the fixed price period, (e.g. 10 years) the QF receives

payment for energy delivered at the full short-run avoided operat-

ing costs which are also paid to QFs under Standard Offers #1

through #3.

This option contains no discounts, requires no security, and has

no formula for calculating damages in the event of nonperform-

ance or breach.

C. Levelized Payment (Option #2)

During the fixed price period, the QF will receive prices

levelized over that period. The forecast from which these

levelized prices are derived is the same as that used in the forecast

or ramped-up energy price option. Prices are time-differentiated,

and will be paid throughout the fixed price period. This option

also does not require any discounts from the utility’s avoided cost.

However, it does require that the QF post security to protect

ratepayers in the event nonperformance occurs and early period

A-24

overpayments have been made. And if the utility accepts a lesser

grade of security, that may not fully guarantee protection of the

ratepayer, then a 1.5% discount from the levelized prices is

applied over the fixed price period (specifics concerning security

and levelization are discussed below in this section). This option

under PG&E’s proposed contract, contains a formula for calculat-

ing minimum damages in the event of breach; however utilities

may also seek to collect foreseeable damages allowed at law for

breach of contract, beyond those specified by the formula.

1. Levelization

This is an opportune place to discuss levelization generally,

because the distinguishing feature of payment Option #2 is a

levelized payment stream.

Levelization is a payment stream where periodic payments are

constant over a period of time, and are based on forecasted values

and the value of money. It works roughly as follows:

| zs sayment stream

“ ~ sme

The payor (e.g., utilities and ultimately their ratepayers) ap-

plies a discount rate to the ramped-up payment forecast in order

to derive an “equivalent” levelized payment stream. As indicated

in the above diagram, the result of levelization is that the payor

pays a higher level of payments earlier in the time period (area A

on diagram) in exchange for lower payments later on (area B on

diagram). The payment streams are “equivalent” if, given the

payor’s opportunities to invest funds (or cost of capital), the

savings in the later years (area B) are equivalent to the return

that the payor could have earned investing the difference between

————

A-25

the forecasted and levelized payments (area A) early on. The

discount rate is that rate of “foregone” compound interest at

which the payor is willing to trade for the burden of paying more

sooner than would otherwise be the case.

Applied to QF-utility contracts, levelization means the utility

will be paying more in the earlier period, and electric rates for

consumers in the early period will be incrementally higher as the

periodic levelized payments are passed on in the utility’s rates.

Also, if the QF quits production before the end of the levelization

overpayment, (time X on the above diagram), the utility and

ratepayers are left having paid more than the commodity was

valued. Our concern about levelization stems from these factors.

In simplest terms, levelization for QF pricing is a form of

ratepayer “loan” to make a perhaps otherwise nonfinanceable QF

project viable enough to attract conventional financing. QFs say

the option of levelization, which is comparable to ratepayers than

their “financing” of utility-owned projects, is only fair. Staff

thinks a solid QF project should be financeable if it has a

guaranteed price stream, as under Option 1, and that a bank or

other investor should make the “loan” needed in early years

instead of the ratepayers. But staff agreed to this levelization

option on an interim basis to see how effectively it facilitates new

QF projects and to see how risky it actually is to ratepayers.

The discount rate negotiated at the conference, to be used in

the utilities’ levelization calculations, was 15%.* If something less

than first class security (as discussed later) is put up by the QF to

ensure ratepayer recovery for overpayments in the event of

nonperformance, an additional 1'2% is taken directly off the

levelized payment stream to compensate ratepayers for the corre-

spondingly higher risk resulting from a lesser grade of security.

There was considerable debate among parties as to the appropri-

ate “opportunity cost of capital’ for ratepayers in levelizing

payment streams for projects of varying technical and financial

risk. If the discount rate used it too high, then ratepayers are not

* PG&E included levelization based payments with both a 132% and

15% discount rate; however, it shall use 15%, consistent with the

agreement reached at the negotiating conference.

A-26

fully compensated for the overpayments in the early years of the

contract; that is, the levelized payment stream is too high.

Levelization and its attendant problems posed by the use of

discounting, security requirements and termination penalties is

something which, in a perfect world, we would prefer not to deal

with, particularly in the context of a standard offer. We have

severa! concerns about levelization as a feature of even an interim

standard offer:

(1) the precedent may lead parties to believe it is the norm;

(2) administering the security provisions of standard offer

contracts with levelization can, as the number of QFs increase, be

an ongoing administrative chore of some magnitude for utilities

(which ultimately translates into additional costs to ratepayers);

and

(3) costs to ratepayers from early contract period “overpay-

ment” caused by levelization acerbates the overall level of electric

rates, which are now higher than we prefer.

We wonder why a large number of QF projects cannot be

financed with the simple forecasted payment stream, which is

guaranteed, assuming performance, up to the first ten years of

operation. The forecasted ramped-up payment stream offered by

the nonlevelization option is a large step forward in terms of

payment certainty for QFs, which should greatly assist with

financing. The specter of many levelized standard offer contracts

concerns us; particularly since we have no evidentiary record that

shows solid viable QF projects cannot be developed or financed

without levelization.

Our solution is to allow utilities to enter levelized standard offer

based contracts for a maximum of one year after the effective

date of the [sic] this order. As indicated in the following order,

we will address lissues [sic] relating to this payment option as

early as possible in evidentiary hearings. And Ithis [sic] option

may be extended though [sic] a subsequent interim order, if we

determine that providing for levelization in a standard offer is in

the continuing public interest. Those who represent QFs have the

burden of showing why levelization is necessary. Our goal is not to

|

A-27

ensure every possible QG [sic] project and/or technology is

financeable; rather, our goal is to provide an economic environ-

ment in which solid, well-conceived projects have a reasonable

opportunity to be financed through prices paid by utilities and

ratepayers. It is not our task to compensate, through standard

offer payment terms, for all concerns and reluctance of lenders

and equity investors. Ours is a world of risks, and we have no

business ensuring that some have little or virtually no risk at the

expense of others (i.e., ratepayers). While we will ratify the

levelized option for use for one year, one purpose of this discus-

sion is to alert parties directly that we have serious reservations

about continuing to provide for levelization in a standard offer.

2. Security Provisions of Levelized Option #2

PG&E very aptly summarizes how the issue of security provi-

sions evolved in the context of the levelization option:

“This proved to be one of the most troublesome issues in the

Settlement Conference. Commission staff wanted QFs to

provide very solid, substantive security in order to assure

ratepayers would be made whole in the event of termination

or nonperformance. QFs wanted the opportunity to substi-

tute lesser security (e.g., liens on their equipment) which is

more readily affordable, and to allow utilities to exercise

discretion in rejecting any ‘inadequate’ security that might be

offered. Utilities were not anxious to have such discretion

within a Standard Offer, because it appeared to present a no-

win situation. The QF developer whose proposed security

was rejected by the utility could complain that the utility was

being unreasonable; if security that the utility accepted

eventually turned out to be inadequate, its prudence could be

questioned by the Commission.

The result is a compromise. Two tiers of security will be

accepted. QFs that provide first class security will be abie to

avoid price discounts; those that provide lesser security will

be subject to a 1.5% energy price discount in the fixed price

period. This lesser security—essentially corporate guarantees

and equipment liens—is subject to acceptance by the utility.

PGandE agreed to this discretionary authority because QFs

A-28

insisted they needed the option of providing lesser security.

PGandE reluctantly accepts this discretionary role in this

Standard Offer and hopes that in any future recovery pro-

ceedings, the Commission will view its exercise of such

discretion within the greater context of promoting alternative

energy resources.” (PG&E’s third amended application,

pages 15 and 16 of Appendix A).

The higher quality security, the amount of which changes each

year as ratepayer exposure is reduced until the levelization mid or

crossover point is reached, is any or a combination of the

following: A letter of credit, performance bond, paid-up non-

cancellable project failure insurance or a solid corporate guaran-

tee acceptable to the utility. Lesser security is other security

which is acceptable to the utility, such as: a less solidcorporate

[sic] guarantee, and liens or a mortgage on the facility and/or the

land on which it is located.

Staff believes that if the utilities have diseretion to reject

second level security, that potential QFs should not be able to

appeal the utilities’ decision te the Commission. We agree. The

ability to provide second level security is a major concession to

responsibility of judging it. The utilities should not be second-

guessed, and we do not want the responsibility for judging security

in individual cases. We expect the evidentiary hearings to develop

even clearer security requirements for this standard offer. A

standard offer should not have discretionary iterms [sic] in it.

Having utilities administer these security provisions is directly

analagous [sic] to their serving in the role as a lender, which in a

real sense they are (with the ratepayers’ money). We can under-

stand their discomfort in this role, but we think the guidelines are

clear enough they can reasonably administer the security provi-

sions. Ultimately, however, we would prefer more concrete secur-

ity provisions if levelization options are extended, and we expect

this issue to be addressed in the evidentiary hearings. directly

analogous to their serving in the role as a lender, which in a real

sense they are (with the ratepayers’ money). We can understand

their discomfort in this role, but we think the guidelines are clear

enough they can reasonably administer the security provisions.

Ultimately, however, we would prefer more concrete security

A-29

provisions if levelization options are extended, and we expect this

issue to be addressed in the evidentiary hearings. [sic]

D. Curtailment Provisions (Under All Payment Options)

The negotiated curtailment provisions for Standard Offer #4

are utility specific, with PG&E’s provisions consisting of the

following 2 options:

(a) Curtailment under “negative avoided cost” conditions

and a lower “hydro spill rate” under hydro spill conditions

with no hourly limit. This option refers directly to this

Commission’s definition of negative avoided costs:and hydro

spill conditions.

(b) A limit of 1,000 hours of real time prices per year for

negative avoided cost, hydro spill and non-oil/ gas units at the

margin. This second option requires some further explana-

tion, as PG&E explains:

“PGandE will not curtail the QF when these conditions

occur, but will instead offer to continue purchases at a

price equal to the current actual avoided energy cost. The

QF can then make its own operating decisions; PGandE

and ratepayers will be indifferent. PGandE will limit the

1,000 hours to off-peak periods, and increase the price in

the other off-peak hours to account for the fact that these

low-cost periods are no longer being averaged in.

“PGandE’s unique system means it will have to have

maximum operating flexibility in the coming years to

efficiently utilize the available resources. The 1,000-hour

option helps provide this necessary flexibility while re-

maining faithful to the avoided cost framework. SCE and

SDGandE are not providing the opportunity for the QF to

remain operational and receive actual avoided costs, but

are instead offering annual hourly curtailment limits.

PGandE does not believe such an approach is appropriate

in its case, and would object to one being imposed”.

(PG&E’s Amended Application, Exhibit A, pages 11-12).

ait

A-30

SDG&E’s negotiated standard offer includes provisions to cur-

tail QF production for up to a total of 300 off-peak hours per year

where such purchases result in “negative avoided cost” to

SDG&E “as such term is defined by the CPUC (SDG&E’s

Amended application, page 22).”

Edison’s offer curtails the QFs production for up to 300 off-

peak hours when:

“(i) purchases would result in costs greater than those

which Edison would incur if it did not purchase energy from

seller but instead utilized an equivalent amount of energy

generated from another Edison source (emphasis added), or

“(ii) the Edison Electric System demand would require that

Edison hydro-energy be spilled to reduce generation”.

(Edison’s Amendment, page 26)°

In D.82-01-103, D.82-04-071, and D.82-12-120, we defined

“negative avoided costs” as a situation where, due to operational

circumstances, purchases from QFs would result in costs greater

than those which the utility would incur if it did not make such

purchases, but instead generated an equivalent amount of energy

itself. We cite such a condition as being when a baseload or large

oil-fired intermediate load plant is shut down at night due to an

excess of QF electricity but then cannot be restarted and brought

up to its rated output for the next day’s peak load, thus necessitat-

ing instead the start-up of a plant with very high generating costs

(e.g., a gas turbine peaker) or an expensive emergency purchase

of capacity. In D.82-04-071 the Commission concluded that,

while curtailment was not appropriate for hydro spill conditions, a

lower “hydro savings” price is appropriate. The decision did not,

however, permit a lower price to be established during periods

when economy energy is purchased or when avoided costs are

positive. Anticipated economy purchases were to be averaged in

the avoided cost applied for the entire time period. Proposals to

restrict the number of hours that curtailment and hydro spill

* The phrase “generated from another Edison source” is interpreted

(by both SCE and the Commission) to exclude economy energy

purchases. Hence, it conforms with Commission policy on this issue.

A-31

conditions apply were denied in D.82-01-103 and D.82-04-071.

However, in D.82-12-120 we directed utilities to undertake stud-

ies which would be considered in reviewing future proposals to

establish such limits.

Only PG&E’s curtailment option a) conforms with our nar-

rowly defined negative avoided cost and hydro spill conditions

established for Standard Offers contracts #1 and #2. We ac-

knowledge the nonconformity of PG&E’s option b) and the other

utilities’ curtailment provisions with our previous decisions. How-

ever, we consider these disparities as part of the negotiation

process and integral to the parties arriving at a negotiated “pack-

age”. We alert parties that these provisions will be reviewed and

evaluated for prospective standard offers in evidentiary hearings.

E. The “Regulatory Authority” Clause

Edison and SDG&E have what are commonly termed “Regu-

latory Authority” clauses, which allow for changing contract

terms if directed by a regulatory agency. Edison’s reads as follows:

“This Contract shall at ail times be subject to such changes

as any regulatory agency may direct in the exercise of its

jurisdiction. If there is any conflict between the provisions of

this Contract and any changes directed by such regulatory

agency, the Parties shall amend this Contract in a manner

consistent with such regulatory changes.”

Both utilities indicated they included this clause consistent with

prior Commission directives with respect to earlier standard

offers. PG&E indicated it was willing to drop this clause because

it seems incompatible with a long-term forecast based and bind-

ing contract, particularly if this Commission clearly intends to

allow utility cost recovery for prices paid under standard offer

contracts.

In view of our holding that contracts entered under Standard

Offer #4 will not be subject to retroactive change based on

prospective developments in the continuing saga of pricing QF

power, we think the regulatory authority clause should be deleted.

In other words, the quid pro quo for giving QFs certainty with

respect to all contract terms, and eliminating the regulatory

j —

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authority clause, is that QFs may not freely switch to other

contracts later, until their contract term is up, if subsequent

contracts or terms appear more favorable. Thus, we are really

exchanging certainty of contract sanctity for certainty of commit-

ment, and given our reaffirmation that cost recovery will be

allowed utilities for all standard offer power purchase contracts,

we think this is only fair. QFs contend that with the regulatory

authority clauses in the contracts of Edison and SDG&E there

will be insurmountable hesitation by lenders because of uncer-

tainty. In ordering the clauses removed we recognize that we

cannot order retroactive changes to interim Standard Offer #4

contracts but, given the restrictions placed on the use and availa-

bility of this negotiated standrd [sic] offer, we are willing to

commit to that loss in flexibility.

F. SDG&E’s Forecast of Marginal Energy Production Costs

and Updating Forecasts

SDG&E requests that its 15-year forecast of marginal energy

and production costs and its corresponding incremental energy

rate be available to price QF power under this standard offer for a

maximum of six months after filing its amended application

which was filed on July 11, 1983 (SDG&E’s amended applica-

tion, pages 5, 9 and 12).

Near the conclusion of the negotiating conference there was

disagreement about the energy rate forecast SDG&E would use

in connection ith its standard offer. Ultimately, SDG&E filed

the forecast most parties thought was agreed to. It did this,

according to its amended application, in the spirit of cooperation;

however, it indicates its most current forecast is lower (SDG&E’s

amended application, pages 5-6). Proposing the consensus agreed

upon forecast, one SDG&E prepared in March 1983, but request-

ing a maximum six month period for its availability for QF

contracts, was done, according to SDG&E, at ALJ Alderson’s

suggestion. Our ALJ offered that suggested compromise as a

means of avoiding what seemed to be a looming and substantial

impasse.

We believe the substance of our ALJ’s suggestion has merit.

However, rather than impose a hard and fixed time cap for use of

ee |

A-33

SDG&E’s filed forecast, we will direct that it be applied to

Standard Offer #4 until further order; and one of the first issues

we want considered at the evidentiary hearings, for expeditious

consideration and decision, is the reasonableness of SDG&E’s

forecast, particularly vis-a-vis the level of Edison’s and PG&E’s.

This approach is preferred because we do not want to get into the

situation of having a hiatus, where prices based on SDG&E’s filed

forecast have lapsed, and a forecast to replace it has not been

approved. Our solution reasonably addresses SDG&E’s concern.

We are not prepared today to address the related questions of

the frequency of updating the forecasts of all utilities, and the

procedural forum or vehicles for updating. Those are issues,

however, that are deserving of all parties’ attention during hear-

ings. The forecasts underlying prices in interim Standard Offer

#4, for the respective utilities shall, in the meantime, be used as

directed in the following order.

Vil. FORECASTED INCREMENTAL ENERGY RATE

PAYMENTS (OPTION #3)

Capacity payments under this option are the same as those

described for Option #1 and #2 (as discussed). However, the

energy prices under this option are based on (1) a forecast of the

utilities’ incremental energy rates and, (2) actual utility costs for

incremental fuel. The incremental energy rate has been referred

to by some parties as the derived and/or incremental heat rate,

which is incorrect. The incremental energy rate is derived from

marginal energy cost forecasts taken from utilities’ production

simulation models; these models include estimates of the costs of

all projected resources at the margin over the term of the forecast.

(e.g., 15 years). Once the marginal energy cost forecast is made it

is then analyzed to determine the primary fuel for the resource

most frequently at the margin, which has turned out thus far to be

oil or gas. The overall annual marginal energy cost is then divided

by the projected incremental fuel cost for that period to produce,

for any given year, a forecast of the incremental energy rate

(which is expressed in Btus/kWh). While this is similar to how

heat rates are expressed, as derived it does not reflect a system

incremental heat rate, because it is derived by only one

fuel/resource and not a weighting of ali resources that may appear

| cea

A-34

at the margin at times over the forecast period. For consistency

among utilities, and to avoid prolonging confusion, this payment

option shall be referred to as the “incremental energy rate”

option, and their contract terms and language shall be amended

accordingly.

Assuming oil or gas generation is the marginal, incremental,

swing generation source, incremental energy costs for utilities are

the product of the incremental energy rate and the price paid for

oil or gas. This pricing formula and payment stream is most

sought by oil and gas cogenerators, as while the forecasted utility

incremental energy rate is fixed, the cost of fuel will be actual;

and, of course, if the cost of utility oil and natural gas rises or falls

there is a direct correlation for the QF’s corresponding costs.

PG&E likes this payment option because it thinks there is less

likelihood, over time, that payments to QFs will deviate from

actual realized utility avoided costs (PG&E’s amended applica-

tion, Exhibit H, page 9).

Under PG&E’s Option #3° the QF will be paid a monthly

incremental energy rate, based on a “derived” incremental heat

rate forecast and the actual price of marginal fuel (i.e., natural

gas or oil). However, there are revisions for making adjustments

should PG&E’s actual incremental energy rate differ from the

projection. The QF, when the contract is signed, can elect a series

of annual band widths, expressed in 100s of Btu/kWh, which are

equally applied above and below the utilty’s [sic] forecast of

incremental energy rates. The lower band serves as a floor, and

the upper band a ceiling. At the end of each year PG&E

determines its actual price of oil and natural gas for its fossil fuel

generating plants and divides this weighted cost into the energy

payments made to the QF over the year. The result of this

calculation is the utility's “actual” (derived) incremental energy

rate. '{ the actual derived heat rate factor for the year is below the

elected lower band, PG&E will make a one-time payment so the

° Although PG&E’s amended application calls this Option #4, for

consistency with the other utility filings, and since PG&E’s designated

Option #3 is not approved by this decision, we refer to this energy

payment Option as #3.

EO)”

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QF receives the value of the lower band for that year; if it falls

above the upper limit of the band the QF makes a similar one-

time payment to PG&E; finally, if it is within the limits of the

band, no payment adjustment is made.

Other than the specifics described above, the contract terms for

Option #1 apply to this option. Thus, this option contains no

discounts, requires no security and, while probably most attractive

to oil and gas cogenerators, is available to all QF technologies.

Once the forecast based payment stream ends, the QF will

receive the then current avoided energy prices.

PG&E proposes the one-time annual reconciliation adjustment,

while Edison would simply compute the price and any adjustment

monthly. PG&E explains why it has a different approach as

foliows:

“PGandE’s heat rate option differs from SCE’s in that it

contains a single value per year, rather than one for each

costing period, and it applies annually rather than monthly.

PGandE believes that these differences reflect utility-specific

differences and that it would be inappropriate to require

PGandE to adopt SCE’s approach. Specifically, there ap-

pears to be an asymmetry across months for HFRs on

PGandE’s system. For instance, a typical year could see 2 or

3 months (in the spring) well below the annual fixed HRF,

and the remaining 9 or 10 months near or slightly above it.

Given a band of the proper width, this could trigger pay-

ments to the QF in the spring, with no compensating

payments the rest of the year. PGandE could develop a

monthly mechanism such as SCE’s; however, we believe that

a) it would by unnecessarily complex, b) PGandE’s structure

provides sufficient pricing certainty for QFs, and c) further

analysis would be required, and lower HRF [sic] values

would likely result.” (PG&E’s amended application, Exhibit

A page 4).

We recognize the benefits of having oil and gas cogenerators on

the system to displace the utilities’ incremental oil and gas

generation units, but only to the extent that: 1) cogeneration

results in a more efficient use of fossil fuels (i.e., the cogenerator’s

———ee

A-36

actual incremental energy rate is lower than the utility’s) and, 2)

California’s resource base, no matter how well it can be diversi-

fied, may require some oil and gas generation units to meet

demand. We are concerned, however, that this energy payment

option could, over time, provide incentives to oil and gas cogener-

ators that are not commensurate with the benefits described

above. Whereas Options #1 and #2 place the entire risk that a

QF’s actual production costs may be higher than our projections

of avoided costs, Option #3 removes the risk associated with fuel-

price variability from fossil-fuel cogenerators. Instead, ratepayers

are exposed to all of the fuel-price variations, which can be very

significant for oil and gas. Furthermore, providing a band around

the incremental energy rate forecast mitigates some of the poten-

tial efficienty [sic] benefits that oil and gas cognerators [sic] can

add to the system.

The issue of the utilitities [sic] forecast of incremental energy

rates was not resolved at the negotiating conference to the

satisfaction of some QFs. At the prehearing conference QFs

indicated they found Edison’s filed forecast acceptable, while

PG&E’s and SDG&E’s were not. QFs request to reopen the

negotiating conference to pursue what, from their perspective,

would be a “better” forecast from PG&E and SDG&E. So, at this

juncture, we see our choices with respect to payment Option #3

of being the following: |) To approve Edison’s Option #3, and

reopen the negotiating conference to consider further the other

utilities’ forecasts; 2) to put all these forecasts back into the

negotiating conference; 3) to allow this payment option, for all

utilities, to be taken up in evidentiary hearings and approve

nothing today with respect to Option #3 or, 4) to approve the use

of Option #3 for all utilities, as filed, on the positive assumption

that some QFs may find it useful pending a complete review of

Standard Offer #4 and all payment options during evidentiary

hearings, during which the feasibility of further negotiations is

always an option.

We think the latter approach is by far the most constructive in

view of our policy reservations concerning this option and our

decision, discussed later, not to reopen the negotiating conference

(our reasons for not reopening the negotiating conference are

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discussed later). QFs, we note, who are dissatisfied with the

incremental energy rate forecasts may compensate to some degree

by selecting a wider band around the utility’s forecast; thus, while

their minimum payments could be lower, their potential maxi-

mum payment could be higher. In any event, we find allowing this

payment option to go into effect extends to QFs another option

and opportunity not now present. Even if only a portion of oil and

gas cogenerator QFs can use this option, it is a material improve-

ment over not having the option available. Also, as discussed

later, QFs may seek a nonstandard contract if they find Option

#3, or any other option or standard offer, does not suit their

needs. The continued availability of nonstandard contracts is

discussed later in this opinion.

In view of the reservations discussed above, we are limiting the

availability of this energy payment option to a maximum of one

year after the effective date of the following order. As we

determined for payment Option #2, we will not extend that

period for payment Option #3 until evidentiary hearings have

addressed these issues and we determine that continuing an

incremental energy rate option beyond one year is in the public

interest.

Vill. UTILITY COST RECOVERY OF PRICES PAID

UNDER STANDARD OFFER CONTRACTS WITH

QFS

At the negotiating conference the utilities raised concerns

about their cost recovery in Energy Cost Adjustment Clause

(ECAC) proceedings, assuming we approve the negotiated in-

terim standard offer. They repeat the concern in their amended

applications.

We thought it was well understood that prices paid QFs under

standard offers approved or mandated by us were per se reasona-

ble for ratemaking purposes. That is one of the hallmarks of the

standard offer. It would be inconsistent and unfair for us to

approve the use of a standard offer and later question the

reasonableness of the prices. While the world may not always be

fair, in our regulatory realm this Commission would never subse-

quently disallow costs necessarily incurred to pay QFs under

A-38

standard offer contracts which we expressly found reasonable at

the outset.

The only possibility for an ECAC ratemaking adjustment

would be if a utility did not diligently enforce all contract

provisions which protect the ratepayers. For example, in the event

of QF breach or nonperformance, we can easily foresee a

ratemaking adjustment if the utility did not take all reasonable

measures to collect damages or to have security called on and

applied to mitigate a loss; damages and called upon security inure

to the ratepayers by a credit to the ECAC balancing account. We

would be derelict if we did not ensure utilities remain diligent in

administering power purchase contracts on behalf of their

ratepayers.

But, with respect to the utilities’ greatest concern, we can only

say that we cannot envision this Commission, or its successor

members, ever being so patently unfair as to attempt to disallow

prices paid QFs under Commission approved standard offers.

IX. CONTRACT TERMS OF INTERIM STANDARD OF-

FER #4 SUBJECT TO RETROACTIVE INCORPORA-

TION RESULTING FROM A.82-03-26 ET AL.

Since the regulatory authority clause of Standard Offer #4 is

being eliminated, we must be very specific about any contract

terms that are subject to retroactive change. Much of Standard

Offer #4 contract language was premised on existing Standard

Offers #1 and #2, which will be subject to another order in A.82-

03-26 et al. Although Standard Offer #4, as proposed, is very

inclusive, there are certain contract terms which should be rea-

sonably consistent with other standard offers; we can direct

consistency without changing the substance of negotiated Stan-

dard Offer #4. Those contract terms fall in the categories of:

(1) PG&E’s line loss factor (PG&E only).

(2) Interconnection procedures and requirements involv-

ing Ifuture [sic] line and system upgrades.

(3) Right of first refusal and mght to purchase on

abandonment.

a

A-39

(4) Insurance requirements.

We are aware, however, of the difficulty for some QFs to

proceed with their projects without a definite clarification of these

final contract terms. We anticipate a decision on A.82-03-26 in

the near future. However, for those contracts signed by both

parties prior to the effective date of a decision on A.82-03-26 et

al. with respect to these terms, we will grant the QF discretion to

decide, within 30 days after the effective date of our decision on

A.82-03-26, whether or not the terms shall be retroactively

changed in his/her contract. In this way, a QF that is ready to

proceed immediately following this order will have the definitive

contract terms with which to approach financial institutions and

the option to have them changed retroactively. However, for any

contract signed by both parties after the effective date of our

decision on A.82-03-26, we order utilities to amend their respec-

tive Standard Office [sic] #4 contract language and terms, for

retroactive application, on the above points consistent with the

outcome in A.82-03-26 et al. No other terms shall be changed by

order of this Commission for retroactive application to executed

Standard Offer #4 contracts.

X. OPPORTUNITY FOR NONSTANDARD- CON-

TRACTS BETWEEN UTILITIES AND QFS

During the prehearing conference QFs asked that we address

whether utilities may still negotiate nonstandard contracts if

proposed Standard Offer #4 goes into effect. Our original direc-

tion on this point in D.82-01-103 remains in effect; that is:

utilities shall negotiate in good faith with potential QFs who do

not want to contract under a standard offer. We expect utilities to

continue to abide by that order. We recently addressed and

amplified some significant procedural and substantive points re-

lating to nonstandard contract negotiations, which are worth

mentioning again for the benefit of all parties (D.83-06-109, in

C.83-05-12, Friant vs PG&E, pages 4-5):

“... Utilities were told to negotiate proposed nonstandard

contracts in good faith with QFs not wanting to accept a

standard offer, but we did not mandate a result. The man-

dated obligation in terms of end result which utilities do have

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is to contract under the applicable adopted standard offers.

As long as utilities negotiate in good faith with respect to

nonstandard contracts, they fulfill our mandate with respect

to those types of contracts. If we allow QFs seeking non-

standard contracts to bring their preferred proposals before

us for ratification, instead of utilities applying for approval

only after their management thinks a nonstandard contract

has merit but wants our ratification in view of cost recovery

concerns, the entire negotiating process would: take a very

different turn from what we envisioned. For then, QFs and

utilities would in essence ultimately ‘negotiate’ with us, and

not each other. We refuse to so directly interject ourselves

into the arena of QF-utility negotiations. Accordingly, we

will not order a ‘result’ based upon a QF’s complaint, but we

will impose sanctions on a utility for bad faith negotiations.

“Although the distinction we draw may seem too subtle or

without solid basis from Friant’s perspective, it is deeply

rooted in the role of the regulator vis-a-vis investor-owned

public utilities. For ordinarily, in the absence of compelling

circumstances, utility management should apply its expertise

and judgment within the regulatory parameters we set; we

must ensure the parameters are fair and in the overall public

interest, but we should not directly ‘manage.’ By the nature

of the relief Friant requests it is asking us to substitute our

judgment for that of the utility‘s management. We will

however make a ratemaking adjustment if we find a utility

had a lower cost option for power (e.g. QF power) which it

did not exercise, or otherwise acted imprudently.”

XI. REOPENING THE NEGOTIATING CONFERENCE

AND SCHEDULE FOR EVIDENTIARY HEARINGS

QFs want to reopen the negotiating conference to pursue

different derived heat rate forecasts from PG&E and SDG&E

with respect to payment Option #3, and to develop a fourth

payment option.’ We have decided not to reopen the negotiating

’ Early in the negotiating conference PG&E proposed an energy floor

price mechanism, which had a fixed price period and a discounting

mechanism in later years to compensate for the guaranteed floor price

A-4]

conference, but as the evidentiary hearing proceeds, we leave it to

the assigned Commissioner to determine whether any negotia-

tions regarding Option #3 will contribute to the ultimate decision

affecting the future of Option #3 beyond the one-year period

provided by this order.

When we announced the settlement conference we stated it

would run for four weeks. Our ALJ allowed it to go for five weeks.

We knew at the outset some parties, at the conclusion of the

negotiating conference, would probably either be dissatisfied with

the results or want it to go longer if not everything was “settled”.

That’s the essence of a negotiating session; there are inherent

frustrations built into that process.

The negotiating conference required a lot of staff expertise and

the participation of our Utilities Division director. Five weeks is

enough. Also, a negotiating conference should be held for only the

period specified at the outset, otherwise parties will, for good

reason, have the expectation that if they do not like the results the

conference can go on and on until they do. And there is always

the real, but undesirable, possibility of Parkinson’s Third Law

starting to apply when we hold negotiating conferences, which, in

during the fixed price period. Then, very late in the negotiating confer-

ence, a variation was proposed by U. S. Windpower, but was not

developed to the point of the various parties (utilities, staff and QFs)

being able to reach a consensus. Of the three utilities, only PG&E

developed this payment option in the amended applications. Edison and

SDG&E, as our staff, think the concept may hold some promise but that

it needs considerable study. Whereas all the other payment options have

prices that are based either completely or substantially on a fixed

forecast, PG&E’s proposed floor price mechanism makes payments to

QFs, over time, based on actual utility avoided costs. However, in the

early years of the contract the prices can set as a floor which can be

above the levelized payment stream prices in Option #2; there is a long

payback period provided for in later years if early year payments

substantially exceed actual avoided costs. The payback period, depend-

ing on the contract term and amount of overpayment, can by substan-

tially longer than the payback period in Option #2. Thus, despite

discounting factors in later years, the issue of risk assessment and

security provisions become even more critical for this proposed payment

option than Option #2.

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essence, is: work always fills the time allowed for it. Another

aspect of reopening the negotiating conference for the specific

purposes proposed by QFs is that it would tend to be taken by all

parties that we strongly expect a certain result (e.g., that SDG&E

and PG&E should raise their derived incremental energy rate

(forecast), or that we conceptually embrace a payment option,

such as the floor price mechanism. We have no reason to believe

any of the energy rate forecasts are too low (or for that matter too

high), or that the floor price mechanism payment option has

conceptual merit. Taking the extraordinary step of ordering nego-

tiations reopened under these circumstances would not do justice

to the concept of allowing parties a fixed time to reach a

negotiated consensus. As this is our first experience with a

negotiating conference in a generic and complex proceeding, and

substantial results have already been accomplished, we do not

think it is either necessary or desirable to reopen it. We are sorry

if some are disappointed by our decision on this point, but as we

said earlier, that’s the negotiating process.

We would have been surprised had some not been disap-

pointed. At this juncture we think it is most constructive for

parties to spend their time to start preparing themselves for

evidentiary hearings, so their prepared showings are complete and

well developed. They are free, in doing this, to exchange ideas and

concepts.

To ameloriate some frustration, disappointment, and possible

economic forebearance, we are, as discussed above, authorizing

the incremental energy rate payment Option #3 for all three

utilities, and not just Edison, so that option is extended through-

out most of the state.

All parties must realize that while we are approving the

negotiated standard offer, they should not assume the methodol-

ogy underlying the derived prices and the contract terms have

significant precedential value in our continuing process of adopt-

ing a standard based on long-run avoided costs. When evidentiary

hearings begin, parties should be prepared to examine and address

all the concepts embodied in the negotiated standard offer.

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When should evidentiary hearings begin? Sorne parties, as

discussed above, are extremely anxious for hearings to star

almost immediately; the utilities would prefer a pause, in essence

to catch their breath and gain some experience with the negoti-

ated standard offer. While we are anxious to proceed with our

continuing and evolving endeavor of valuing and pricing QF

power, and establishing a lasting standard offer based on long-run

avoided costs, we think it would be very useful for the parties to

digest, evaluate, and reflect on what has been done thus far in

preparing for hearings. Hearings, we believe, should start in early

1984, with another prehearing conference in December of 1983.

The prehearing conference will be set by a separate notice.

XII. EFFECTIVE DATE OF THIS OPINION AND

ORDER

We think that Standard Offer #4 and its three payment

options, which are approved and adopted by this opinion and the

following order, are a significant step toward valuing and pricing

QF power over the long term. QFs have gained some more

standard offer options, which can only help stimulate new projects

and facilities.

Given the consensus reached, we do not anticipate receiving

applications for rehearing on this interim decision. Accordingly,

we will make the following order effective the date of signature.

We also do this because we think it is in the public interest to

have Standard Offer #4, albeit a negotiated and interim standard

offer, available for use as soon as possible. However, it is possible

that applications for rehearing may be filed within the time period

after the order’s effective date as set out in Public Utilities Code

§ 1731, and we expect utilities not to actually enter or sign

contracts under Standard Offer #4 for at least 30 days after today,

and until any such applications for rehearing, if they are filed, are

acted on by us. We take this measure as a procedural safeguard,

in fairness to all parties, in view of our acting without an

evidentiary record upon which to make findings of fact sufficient

to issue a decision to withstand judicial review.

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XIII. FINDINGS OF FACT AND CONCLUSION OF

LAW

Findings of Fact

1. D.83-05-038 announced a negotiating conference for these

consolidated proceedings. That conference was publicly noticed,

open to the public, and lasted from May 23 through June 24,

1983.

2. The amended applications in these proceedings, with the

changes noted on the record during the second prehearing confer-

ence, contain Standard Offer #4. That standard offer, and three

payment options under it, are acceptable to the respective utili-

ties, QFs, and staff, for interim use.

Conclusion of Law

The standard offers filed by the applicant utilities should be

ratified for use by utilities and QFs in contractual power

purchases, as authorized and restricted by the following order.

INTERIM ORDER

IT IS ORDERED that:

1. Standard Offer #4, Payment Options #1 through #3, as

proposed by the Pacific Gas and Electric Company (PG&E), San

Diego Gas and Electric Company (SDG&E), and Southern

California Edison Company (Edison), shall be used by those

utilities until further order of this Commission, but, in any event,

for a minimum of six months and for a maximum of two years

after the effective date of this order. However, in exercising those

payment options under Standard Offer #4 the following restric-

tions or conditions shall apply:

a. Qualifying facilities (QFs) who are under a power

purchase contract with a utility, either a contract under a

standard offer or a nonstandard contract, shall not enter a

contract based on Standard Offer #4 until their existing

contract term is up.

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b. Only QFs who are not under contract and who have

not completed their facility as of the effective date of this

order may elect Payment Option #2.

c. The “regulatory authority” clause in SDG&E’s and

Edison’s Standard Offer #4 shall be eliminated.

d. QFs who enter contracts under Standard Offer #4 will

not be allowed to switch to a subsequent version of Standard

Offer #4, or to other standard or nonstandard contracts, until

the term of their contract is up.

e. Payment Options #2 and #3 shall be extended and

exercised by utilities for a maximum period of one year after

the effective date of this order.

f. The terms in Standard Offer #4, Options #4, Options

#1, through #3, are subject to change and retroactive

application in contracts signed by both parties after the

effective date of a decision in A.82-03-26 et al., and depend-

ing on the outcome in that proceeding, with respect to:

1. PG&E’s line loss factor.

2. Interconnection provisions involving future lines

and system upgrades.

2 ='asurance.

4. Right to first refusal and right to purchase and

abandonment.

For contracts signed by both parties (QF and utility) prior

to the effective date of a decision on the above terms in

A.82-03-26 et al. the QF has the option of deciding to keep

the terms as set forth in the signed contract if the QF notifies

the utility of this decision in writing within 30 days after the

effective date of the Commission decision on A.82-03-26.

g. PG&E shall use a 15% discount rate for its levelized

payment stream under Option #2.

Any other ordered changes to Standard Offer #4 will be for

prospective application only in new contracts.

ee

A-46

2. A QF which enters a contract under Standard Offer #4, as

approved by this order, may not switch to another contract until

the term of its Standard Offer #4 contract has expired or it has

terminated; if a QF terminates early by breaching the contract the

utility is under no obligation to enter a new contract or to

purchase the QF’s power until: (1) minimum damages are paid if

a minimum damages clause in the contract is applicable; or (2) if

there is no applicable minimum damages clause, until foreseeable

damages have been paid to the utility. The payment of minimal

damages shall not discharge the breaching QF from ultimate

payment of foreseeable damages caused by the breach. Utilities,

on behalf of their ratepayers, shall vigorously pursue recovery of

all foreseeable damages in the event of a QF breaching a power

purchase contract.

3. Prices paid to QFs for power purchased under Standard

Offer #4 provisions, and contracts as under any standard offer,

will be recovered through the ECAC balancing account, and any

collection the utilities make with respect to recovering for dam-

ages or called on security shall be credited to that balancing

account. However, utilities will be subject to ECAC ratemaking

adjustment if it is demonstrated they did not diligently enforce all

contract provisions.

4. Another prehearing conference shall be scheduled and held

before evidentiary hearings begin. Its purpose will be to determine

the order in which issues shall be addressed, dates for exchanging

prepared testimony, and to set hearing dates. The issues that shall

be addressed as early as possible in evidentiary hearings, and

which we may address by another interim order, are:

a. SDG&E’s forecast of energy production costs.

b. Whether the levelized energy payment and the incre-

mental energy rate payment options should be extended for

Standard Offer #4 beyond the one year period as ordered

above.

5S. PG&E, SDG&E, and Edison shall confer among them-

selves and with our staff to devise uniform Standard Offer #4

contract language, except for the very few terms which must be

utility specific due to different operating characteristics. They

A-47

shall jointly submit their proposed uniform contract language as a

compliance filing in these proceedings within six months from

today (making the filing with the Docket Office and serving all

appearances). Their proposed uniform contract language shall not

be effective or used in contracts until it has been approved by this

Commission.

This order is effective today.

Dated September 7, 1983, at San Francisco, California.

I abstain.

/s/ PRISCILLA C. GREW

Commissioner

LEONARD M. GRIMES, JR.

President

VICTOR CALVO

DONALD VIAL

Commissioners

Commissioner William T. Bagley,

being necessarily absent, did not

participate.

A-48

APPENDIX A

Page |

List of Appearances

Applicants: Larry C. Mount, Attorney at Law, for Southern

California Edison Company; Wayne P. Sakarias, John R. Asmus,

Jr., and Vincent D. Bartolomucci, Attorneys at Law, for San

Diego Gas & Electric Company; and Charles W. Thissell and Jo

Ann Shaffer, Attorneys at Law, for Pacific Gas and Electric

Company.

Interested Parties: Roy Alper, Attorney at Law, for Indepen-

dent Power Corporation; Chickering & Gregory, by C. Hayden

Ames, Attorney at Law, for Geothermal Generation, Inc.; Pills-

bury, Madison & Sutro, by Michael R. Barr, Attorney at Law, for

Pillsbury, Madison & Sutro; Hanna & Morton, by R. Lee Roberts,

Attorney at Law, and Henwood Associates, Inc., by David

Branchcomb, for Ultra Systems, Inc., and Occidental Geother-

mal, Inc.; Donald C. Davis, for Herzog Contracting Corporation;

Nicole A. Clay, for San Diego Energy Recovery Project

(SANDER); Frank F. Duquette, for McDonnell Douglas; Joseph

Egan, for University Energy; Paul H. Eichenberger, for SAI

Engineers, Inc.; Mark R. Farman, for Resource Management

International, Inc.; Michel Peter Florio, Attorney at Law, Jon

Elliott, and Sylvia Siegel, for Toward Utility Rate Normalization

(TURN); Lee Freeman, Douglas Porter, and Jon Castor, Attor-

neys at Law, for Pacific Lighting Energy Systems; Janice G.

Hamrin, and Dan Richard, Attorney at Law, for Independent

Energy Producers Association; Richard C. Hill, for Tosco Corpo-

ration; Nossaman, Guthner, Knox & Elliott, by Peter C. Hoffman,

Attorney at Law, for Applied Power Technology, Inc.; Neal A.

Johnson, for California Solid Waste Management Board; Jim

Kaiser, for Sierra Energy and Risk Assessment; Laura B. King,

for Natural Resource Defense Council; Jane S. Kumin, for

Natomas Company; C. M. Laffoon, for Geothermal Generators,

Inc.; Mark Lyons, Attorney at Law (New York, Washington,

D.C.), for Ultra Systems, Inc.; P. R. Mann & Associates, by

Philip R. Mann, Attorney at Law, for California Manufacturers

Association; William B. Marcus, for California Hydro Systems,

Inc.; Kenneth R. Meyer, for Energy Consulting Group; Martin C.

A-49

Recchuite and Michael J. Myers, Attorney at Law, for ARCO

Solar, Inc.; Brown, Vence & Associates, by Tom Reilly, for

Brown, Vence & Associates; Donn Ruotolo, for Ebasco Services,

Inc.; James Samis, for Thermonetics, Inc.; Gary D. Simon, for

Sigma Group; Graham & James, by James D. Squeri, Attorney at

Law, for Union Oil Company of California; Messrs. Downey,

Brand, Seymour & Rohwer, by Philip A. Siohn, Attorney at Law,

for Federal Paper Board, Inc., and Sutherland, Asbill and Bren-

nan, Attorneys at Law; William E. Swanson and Jasper Williams,

Attorney at Law, for Stanford University; Randall M.

Tinkerman, for American Energy Projects, Inc.; Frederick S.

Waiss, Attorney at Law, for Stauffer Chemical Company; Gregg

Wheatland and Kathy Weinheimer, Attorneys at Law, for Cali-

fornia Energy Commission; Cooper Engineers, by Mark White,

for West County Agency; Harry Winters, for University of Cali-

fornia; Matthew J. Wristbridge, Attorney at Law, for General

Electric Company; Donald G. Salow, for Stone & Webster,

Margaret E. Rueger, for U. S. Windpower, Inc.; and Reed V.

Schmidt and Norman Ross Burgess, for themselves.

Commission Staff: Brian T. Cragg, Attorney at Law, and John

D. Quinley.

(END OF APPENDIX A)

A-50

APPENDIX C

Decision 83-12-050 December 20, 1983

Before the Public Utilities Commission

of the State of California

Application 82-04-44

(Filed April 21, 1982; amended April 28, 1982,

July 19, 1982, July 11, 1983, and August 2, 1983)

Application 82-04-46

(Filed April 21, 1982; amended May 12, 1982,

July 11, 1983, and August 10, 1983)

Application 82-04-47

(Filed April 21, 1982; amended

July 11 and August 2, 1983)

Second Application of Pacific Gas and Electric Company

for Approval of Certain Standard Offers Pursuant

to Decision No. 82-01-103 in Order Instituting

Rulemaking No. 2.

And Related Matters.

(See Decision 83-09-054 for Appearances. )

OPINION ON PETITIONS FOR

MODIFICATION OF DECISION 83-09-054

On September 7, 1983 we issued Decisicn (D.) 83-09-054,

which was an interim decision, adopting three payment options

for Standard Offer No. 4. These options are to be used by the

three applicant utilities in these consolidated proceedings. Our

decision followed after a five-week negotiating conference and,

subsequentl;, a prehearing conference lasting two days.

Petitions for modification were filed by the Independent Energy

Producers (IEP) and Occidental Geothermal, Inc. (Occidental);

a response to both petitions was filed by Southern California

Edison Company (Edison), and [EP responded to Occidental’s

petition.

A-51

Occidental’s Petition

Occidental points out that our D.83-09-054 directed the utili-

ties to delete the regulatory authority clause, but that Edison’s

contract contains another clause, termed the “amendment

clause” which Occidental thinks could have substantially the

same effect as the regulatory authority clause that was deleted.

We ordered the regulatory authority clause deleted to afford

qualifying facilities (QF) the certainty and sanctity of contract

terms and fixed term prices they wanted, but in exchange we did

not allow subsequent contract switching. The regulatory authority

clause, of course, could have allowed us to essentially change

contract terms retroactively. Edison’s response is that although

the “amendment clause” would apply only if both Edison and the

QF agreed that there was a “change in circumstances” necessitat-

ing a change in the contract terms, it does not object to removing

the clause if keeping it in the contract alarms QFs. We will direct

Edison to remove the amendment clause from its Standard Offer

No. 4.

The second point raised by Occidental is that Edison’s Stan-

dard Offer No. 4 is not clear that after the fixed price term or

prior to the time of firm delivery, the QF will receive energy

payments based on Edison’s full avoided operating cost as deter-

mined now for Standard Offer No. 2 (for firm delivery based on

short-run avoided cost). Edison’s response on this point is essen-

tially that it did not mean to build any ambiguity into the

contract. It agrees to change the relevant contract provisions by

inserting the language underlined below (see Attachment A-7 to

Edison’s response):

Seller shall be paid 2 Monthly Energy Payment for Energy

delivered by Seller and purchased by Edison at a rate equal

to 100% of Edison’s published avoided cost of energy based

on Edison’s full avoided operating cost as updated periodi-

cally and accepted by the Commission.

We think the amended contract language proposed by Edison

in its response to Occidental’s petition is clear enough. Occiden-

tal’s expressed fear is that a future Commission may decide that

QFs should be paid 80% of utilities’ full operating costs, and that,

A-52

instead of 100%, only 80% wouid be paid by Edison. With

Edison’s proposed amendment all the Standard Offer No. 4

contracts refer to “full avoided operating cost.” Because the fixed

term is 10 years, it is extremely difficult to estimate what short-

run avoided costs will be after that period. But it is clear QFs -

under Standard Offer-No. 4 contracts will receive 100% of full

avoided cost as those costs are then determined and accepted by

this Commission. That is all the certainty contemplated at the

negotiating conference, and it is all the certainty we can extend at

this time.

Furthermore, on November 16, 1983, Occidental responded to

Edison’s response by applauding “Edison’s good faith in making

these important modifications.” Occidental therefore seeks to

withdraw its petition. IEP, similarly seeks dismissal of that

portion of its petition supporting Occidental’s petition. We will

direct Edison to amend its contract language as proposed. No

further amendment is necessary or appropriate.

IEP’s Petition

IEP, in addition to supporting the points addressed by Occiden-

tal, takes exception to the procedure we set out in D.83-09-054 to

initiate the process of having a standardized Standard Offer No.

4. We ordered the three utilities and our staff to work together to

develop standard contract language, with the resulting proposed

contract to be reviewed in subsequent hearings. While pleased

with our effort for more standardization, IEP thinks QFs will be

unfairly prejudiced by not being part of all meetings on the

subject between the utilities and our staff.

We adopted the procedure because we thought it could expe-

dite at least getting a work product for the many and various QF

interests that are parties to these proceedings to review and react

to. We thought the initial logistics fo- the undertaking, which is a

complex task, would be more expedient: The many QF represent-

atives will have full opportunity to review the work product filed

by the utilities. Rather than modify the procedure, we suggest

that our staff arrange an informal meeting with the utilities and

QFs shortly after the utilities file the proposed standard language,

which will be served on all parties. Thereafter, any remaining

Nees

A-53

concerns and issues can be more succinctly addressed during

hearings. We will not modify the procedure as requested by IEP.

We will, however, order the utilities to file the standard contract

language six months from today.

Conclusion

Standard Offer No. 4, along with the energy price, incremental

energy rate and shortage value forecasts adopted by D.83-09-054

has become effective. New incremental energy rates and/or

avoided capacity cost values that may be adopted by the Commis-

sion in general rate case or ECAC proceedings will not affect the

price forecasts established over the fixed payment term under

Standard Offer No. 4, until further orders are issued in this

proceeding.

No applications for rehearing were filed after D.83-09-054 was

issued. We trust there will be no further petitions for modification

of that decision, as parties should raise any concerns or proposals

relating to Standard Offer No. 4 at the upcoming evidentiary

hearing. We will be very reluctant to indulge any petitions that

may address or propose piecemeal changes to existing Standard

Offer No. 4, because it is being relied on by QFs and utilities

alike. Efforts for ex parte modification only cloud an overall

endeavor to bring some clarity and certainty so that the QF

industry can analyze the standard offers available and make its

choices. Procedurally, the next step for parties interested in this

standard offer, and any changes for prospective application is to

raise these points in the evidentiary hearings.

Findings of Fact

1. The modifications Edison proposes for its Standard Offer

No. 4 contract, contained in its response to IEP’s and Occiden-

tal’s petition, are reasonable and should be adopted.

2. QFs are not unduly prejudiced or denied due process by

the procedure D.83-09-054 established to have uniform standard

contract language proposed.

A-54

Conclusions of Law

1. The petition for modification filed by Occidental should be

granted, while IEP’s petition should be granted in part and denied

in part in accordance with our findings in this order.

2. The following order should be effective today to bring

certainty quickly and enable QFs and others to expeditiously

evaluate contract options.

ORDER

IT IS ORDERED that:

1. Southern California Edison Company (Edison) shall

amend its Standard Offer No. 4 as it proposes in its response to

the petitions for modification filed by the Independent Energy

Producers (IEP) and Occidental Geothermal, Inc. (Occidental).

2. The petition for modification of Occidental is granted with

respect to Edison’s removing the “amendment clause” of its

Standard Offer No. 4 contract, and it is granted to the extent of

Edison’s proposed modifications with respect to the energy price

to be paid either before firm production or after the fixed price

term.

3. IEP’s petition for modification is granted with respect to

Edison’s being ordered to delete its amendment clause, but

denied concerning its proposed modification of the procedure in

Ordering Paragraph 5 of D.83-09-054.

4. The compliance filing ordered by Ordering Paragraph 5 of

D.83-09-054 shall be filed no later than six months from today.

A-55

This order is effective today.

Dated December 20, 1983, at San Francisco, California.

I abstain because of reportable financial

interest in potential small power

producers.

/s/ PRISCILLA C. GREW

Commissioner

LEONARD M. GRIMES, JR.

President

VICTOR CALVO

DONALD VIAL

WILLIAM T. BAGLEY

Commissioners

ee

A-56

APPENDIX D

Decision 84-08-035 August |, 1984

Before the Public Utilities Commission

of the State of California

Application 82-04-44

(Filed April 21, 1982;

amended April 28, 1982,

July 19, 1982, July 11, 1983

and August 2, 1983)

Application 82-04-46

(Filed April 21, 1982;

amended May 12, 1982,

July 11, 1983, and

August 10, 1983)

Application 82-04-47

(Filed April 21, 1982;

amended Juiy 11, 1983

and August 2, 1983)

Second Application of PACIFIC GAS AND ELECTRIC

COMPANY for Approval of Certain Standard Offers Pursuant

to Decision No. 82-01-103 in Order instituting Rulemaking

No. 2. And Related Matters.

OPINION MODIFYING DECISION 83-09-054

By Ordering Paragraph | of Decision (D.) 83-09-054, this

Commission ordered that “Standard Offer No. 4, Payment Op-

tions Nos. | through 3, as proposed by Pacific Gas and Electric

Company (PG&E), San Diego Gas & Electric Company

(SDG&E), and Southern California Edison Company (Edison)

shall be used by those utilities until further order of this Commis-

sion, but, in any event, for a minimum of six months and for a

maximum of two years after the effective date of this order.”

With respect to Payment Options Nos. 2 and 3, the utilities were

to exercise these options for a maximum period of one year after

the effective date of the order. Because D.83-09-054 became

A-57

effective on September 7, 1983, these payment options are due to

expire on September 7, 1984.

Standard Offer No. 4 was the result of a negotiating conference

held during the summer of 1983. The goal of the negotiating

conference was to develop an interim Standard Offer No. 4 which

the parties “could comfortably tolerate and work under while

refinement and ‘perfection’ could be pursued in subsequent evi-

dentiary hearings.” (D.83-09-054, at p. 8.)

By Administrative Law Judge’s (ALJ) Rulings issued during

1984, the procedure to be followed in these “subsequent eviden-

tiary hearings” was established. The proceeding has been divided

into two phases—Phase I which will focus on the appropriate

costing methodology for Standard Offer No. 4 and Phase II which

will examine the prices based on the adopted methodology,

appropriate price approaches, and all other terms of Standard

Offer No. 4. Hearings for Phase I began on July 23, 1984.

On May 7, 1984, the Commission staff filed a “Recommenda-

tion of the Commission Staff to Establish Procedures for Phase I

of the Long-Run Offer Hearings.” Among other things, the staff

observed that because Phase I was limited to an examination of

costing methodologies, it would be appropriate to defer issues

related to payment options until Phase II as directed by the ALJ.

Under these circumstances, it is the staffs opinion that energy

Payment Options Nos. 1, 2, and 3 and the energy price forecasts

adopted in D.83-09-054 be extended until the conclusion of Phase

II. The staff asserts that this approach will preserve the status

quo, enabling qualifying facilities (QFs) to have the benefit of

energy price certainty and eliminating any need to analyze and

adopt incremental energy rates prior to Phase II.

During the prehearing conference of May 9, 1984, the staff

reiterated these recommendations. While there were no objec-

tions to the recommendations, at least one party requested that

the incremental energy rate to be paid the QF by PG&E under

Option No. 3 be based on the incremental energy rate approved in

PG&E’s most recent general rate case.

On June 15, 1984, Independent energy Producers (IEP) filed a

motion for a revised procedural schedule for the Standard Offer

A-58

No. 4 proceeding. Specifically, IEP requests that (1) interim

Standard Offer No. 4, Payment Options 1, 2, and 3 be continued

through the end of 1986 or until the issuance of a final decision in

this proceeding; (2) hearings on the “costing methodology” be

commenced as scheduled by the ALJ; (3) hearings on a revised

incremental energy rate be commenced no later than Octover

1984; and (4) hearings “‘on the broader assumptions and terms of

a final Standard Offer No. 4” be commenced after the Commis-

sion issues its decisions on costing methodology and an interim

incremental energy rate pricing option. According to IEP, the

incremental energy rate used for purposes of interim Standard

Offer No. 4 is not a viable option for gas-cogenerated QFs.

IEP’s motion is supported by the Independent Power Corpora-

tion (IPC). IPC further asks that PG&E’s SDG&E’s and SCE’s

interim Standard Offer No. 4 incremental energy rates be modi-

fied to reflect information developed in their most recent general

rate cases.

WE have reviewed these comments and concur with the staff,

IEP, and IPC regarding the extension of negotiated Standard

Offer No. 4. At the time we issued D.83-09-054 we contemplated

that the issues related to the payment options would have been

explored in evidentiary hearings prior to the expiration date set for

Payment Options Nos. 2 and 3. In fact, we optimistically forecast

the conclusion of these hearings as early as six months from the

issuance of D.83-09-054. Unfortunately, only hearings on Phase |

of this proceeding will be concluded prior to September of this

year, with Phase II commencing after that time.

Under these circumstances, and given the general acceptance

of interim Standard Offer No. 4, we will extend the effective date

of the terms of that offer, including Payment Options Nos. 1, 2,

and 3, and the energy price forecasts adopted in D.83-09-054.

This extension, which applies to all terms of the offer, will be

effective until further order of this Commission.

We will not, however, amend Payment Option No. 3 in any

way. That payment option was part of the negotiated package

which the Commission approved on D.83-09-054. A change in

one term would require the reexamination of all other terms of the

A-59

standard offer. We prefer to maintain the status quo and adopt

modifications to Standard Offer No. 4 following the evidentiary

hearings now scheduled in this proceeding. We also note that a

QF who finds the terms of interim Standard Offer No. 4 unac-

ceptable may in fact negotiate a separate contract. Despite some

QFs dissatisfaction with that remedy, we have made clear in

previous decisions that all utilities are to negotiate with QFs in

good faith.

With respect to the requests for October hearings on the

utilities’ incremental energy rates, we are unable to commit our

limited resources to such hearing dates at this time. At the most,

we can reiterate that hearings on Phase I began on July 23, 1984.

Upon completion of that phase, the Commission will make a

determination either in its decision in Phase I or by ALJ Ruling

whether to segregate the issue of incremental energy rate valua-

tion and hear the matter prior to Phase II hearings.

Findings of Fact

1. A reasonable modification of D.83-09-054 has been re-

quested by the Commission staff, IEP, and IPC to extend the

effective date of interim Standard Offer No. 4.

2. The other requested modifications of the Standard Offer

No. 4 procedural schedule cannot be adopted at this time.

Conclusions of Law

1. The terms of interim Standard Offer No. 4 approved in

D.83-09-054 should be extended until further order of this

Commission.

2. The motion of IEP should be denied, except to the extent

granted in keeping with Conclusion of Law 1.

3. To ensure the extension of Standard Offer No. 4 before it

would otherwise expire, this order should be made effective today.

A-60

ORDER

IT IS ORDERED that:

1. All terms and conditions of interim Standard Offer No. 4

adopted in D.83-09-054 shall be extended until further order of

this Commission.

2. The motion of Independent Energy Producers, except to

the extent granted by Ordering Paragraph 1, is denied.

This order is effective today.

Dated August 1, 1984, at San Francisco, California.

LEONARD M. GRIMES, JR.

President

VICTOR CALVO

DONALD VIAL

Commissioners

Commissioner Priscilla C. Grew, be-

ing necessarily absent, did not

participate.

Commissioner William T. Bagley,

being necessarily absent, did not

participate.

A-61

APPENDIX E

Decision 85-04-075 April 17, 1985

Before the Public Utilities Commission of the State of

California

Application 82-04-44 (Filed April 21, 1982; amended April 28,

1982, July 19, 1982, July 11, 1983 and August 2, 1983)

Application 82-04-46 (Filed April 21, 1982; amended May 12,

1982, July 11, 1983, and August 10, 1983)

Application 82-04-47 (Filed April 21, 1982; amended July 11,

1983 and August 2, 1983

Second Application of PACIFIC GAS AND ELECTRIC

COMPANY for Approval of Certain Standard Offers Pursuant

to Decision No. 82-01-103 in Order Ins ituting Rulemaking

No. 2

And Related Matters.

INTERIM OPINION

I. Summary

This decision continues the suspension of Payment Option No.

3 of interim Standard Offer (SO) 4 for Qualifying Facility (QF)

projects over 50 megawatts (MW), which had been ordered

earlier for Pacific Gas and Electric Company (PG&E) and

Southern California Edison (SCE). It also extends the suspen-

sion for projects over 50 MW to Payment Option No. 3 of interim

SO 4 for San Diego Gas and Electric Company (SDG&E). It

presents two options for comment regarding continued availability

and terms of all of Payment Option No. | and Payment Option

No. 2, and of Payment Option No. 3 for projects less than 50

MW, prior to availability of a final long-run standard offer.

In assessing whether the existing standard offers continue to

provide a reasonable protection for ratepayers, we have relied

primarily on the utility filings of the results of project information

questionnaires sent to QFs as part of our adopted Interconnection

Priority Procedure (IPP), and on the information contained in

A-62

the utilities’ most recent Quarterly Status Reports (QSRs) con-

taining data current through the end of 1984. We conclude that

the capacity payments in the interim SO 4 and the energy

payments in Payment Option No. | and Payment Option No. 2 of

the interim SO 4 would over-value additional QF projects not

already under contract to the utilities. This is true for all sizes of

QF projects and for SDG&E as well as for PG&E and SCE.

The Public Staff has recommended an immediate suspension

of all payment options of interim SO 4 for PG&E and SCE until a

final SO 4 is available, unless prices are adjusted to reflect current

conditions. We agree with Public Staff that further study is

needed of the implications of large cogeneration projects over 50

MW for utility resource planning purposes. Because of the poten-

tially large impact of such projects on system avoided costs, we

prefer that they not be allowed to sign Payment Option No. 3

until we understand more fully the utilities’ long-run costs

avoided by such projects as part of Phase II of the current long-

run pricing proceeding.

Such caution does not appear warranted for other projects,

however. Because of our continued wish to encourage cost-

effective QF development, and because of the continued uncer-

tainty regarding how many signed QFs will actually complete

their projects and operate successfully, we are reluctant to sus-

pend interim SO 4 entirely. At the same time, because of our

desire to not delay further the development of a final SO 4, we see

only one other realistic approach to providing for the protection of

ratepayers at this time: that is for us to modify the interim SO 4

prices offered to new QFs which have not yet signed contracts to a

level which reflects the value of additional QF projects more

realistically. This action would maintain the availability of interim

SO 4 contracts for most projects while final SO 4 terms are being

developed, yet not unduly delay the final SO 4 proceedings.

With this in mind we present a method for adjusting the

capacity payments in PG&E’s and SCE’s interim SO 4 contracts,

based on calculations provided by our staff at the request of the

assigned Commissioner, and detailed in Appendix A. The capac-

ity payments in SDG&E’s interim SO 4 would be modified to

those adopted for its SO | and SO 2 in its most recent general

A-63

rate case. We also propose that the energy payments in payment

Option No. | and Payment Option No. 2 be reduced by 10

percent, but conclude that no adjustment to the incremental

energy rates in Payment Option No. 3 for projects under S50 MW

is warranted at this time.

The revised interim SO 4 contracts would be in effect for each

utility only until a set amount of new QF capacity enters into

contracts, standard or non-standard, with the utility. That amount

is 1,250 MW for each of PG&E and SCE and 200 MW for

SDG&E, counted from April 17, 1985. At that point, all of

interim SO 4 would be suspended for that utility until a final long-

run standard offer becomes available. Projects signing revised

interim SO 4 contracts would have to comply with the milestones

adopted in our Interconnection Priority Procedure.

We provide for a workshop on May 3, 1985, in which staff will

be available to answer any questions parties may have regarding

the calculations underlying the capacity adjustment, and for

parties to file written comments by May 10, 1985, stating whether

they prefer complete suspension of interim SO 4 or implementa-

tion of the capacity and energy payments presented in this

decision. Based on the filed comments, we plan to choose between

the two approaches by June 5, 1955.

To prevent a “gold rush” of projects wanting to sign the current

interim SO 4, we suspend all payment options of interim SO 4,

effective immediately, pending further Commission action.

Il. Background

We first authorized what is termed interim Standard Offer 4 in

September 1983, by Decision (D.) 83-09-054. The three payment

options under SO 4 resulted from a negotiating conference among

the parties, held at our direction. A final SO 4 based on the

utilities’ long run avoided costs is being developed through evi-

dentiary hearings. However, there was substantial agtreement

among utilities, QFs, and our staff that such an interim solution

should be in effect until the final SO 4 becomes available. Briefly,

the three payment options are as follows:

A-64

Payment Option No. I provides increasing energy payments

which are set for the first 10 years of the contract at the time

the contract is signed. Oil or gas-fired cogenerators are

allowed to receive only 20 percent of their energy payments

under Option 1.

Payment Option No. 2 provides fixed, levelized energy pay-

ments based on Option | forecasts of energy prices, for the

first 10 years of the contract. Since energy payments in the

early years are larger than their value to the utility, QFs must

post security and must pay damages if they do not perform

for the duration of the levelization period. Oil or gas-fired

cogenerators cannot sign Option 2 contracts.

Payment Option No. 3 provides “incremental energy rates”’

which are fixed at the time the contract is signed, for up to 10

years. The QF receives energy payments which are the

incremental energy rates times the gas (or oil, if it is the

marginal fuel) price at which the utility buys fuel for its own

generation facilities. For PG&E, the QF can select a band

width around the forecast incremental energy rates, and will

receive payments based on the floor or ceiling of the band

width if PG&E’s realized incremental energy rates are

outside the band width.

For any of the three payment options, QFs may elect to deliver

either firm or as-delivered capacity, with capacity payments equal

to those in effect for SO | or SO 2 at the time of the negotiating

conference, for as-available or firm capacity respectively.

While all the parties participating in the negotiating conference

were in general agreement regarding the reasonableness of Pay-

ment Option No. | and Payment Option No. 2, the issue of the

utilities’ forecast of incremental energy rates was not resolved at

the negotiating conference to the satisfaction of some QFs. QFs

indicated that they found SCE’s filed Payment Option No. 3

acceptable while PG&E’s and SDG&E’s were not, and requested

that the negotiating conference be reopened to pursue what, form

their perspective, would be a “better” forecast from PG&E and

SDG&E.

A-65

In D.83-09-054 we declined to reopen the negotiating confer-

ence, and approved the terms of Payment Option No. 3 as filed by

PG&E andSDG&E, “on the positive assumption that some QFs

may find it useful pending a complete review of Standard Offer

#4 and all payment options during evidentiary hearings, during

which the feasibility of further negotiations is always an option.”

(D.83-09-054, p. 46.)

In D.83-09-054, The Commission specified that Payment Op-

tion No. 1 would be in effect for at most two years, and that

Payment Option No. 2 and Payment Option No. 3 would be

available for only one year, due to reservations about whether

longer provision of these options would be in the public interest.

Our intent at that time was that a final SO 4 would be approved

by the set expiration dates. When this proved overly optimistic,

we extended by D.84-08-035 all three payment options of interim

SO 4 until further order.

D.84-08-035 also addressed a motion for a revised procedural

schedule for the SO 4 proceeding which had been filed by the

Independent Energy Producers Association (IEP) and supported

by the Independent Power Corporation (IPC). These two parties

requested that hearings on a revised incrementai energy rate for

use in Payment Option No. 3 of Interim SO 4 be commenced no

later than October 1984. According to IEP, the incremental

energy rate in interim SO 4 is not a viable option for gas-fired

cogeneration projects. In D.84-08-035 we denied IEP and IPC’s

request, stating that:

““A change in one term would require the reexamination of

all other terms of the standard.

“A change in one term would require the reexamination of

all other terms of the standard offer. We prefer to maintain

the status quo and adopt modifications to Standard Offer No.

4 following the evidentiary hearings now scheduled in this

proceeding.

A-66

“Upon completion of [Phase I of the hearings on a final SO

4], the Commission will make a determination either in its

decision in Phase I or by ALJ Ruling whether to segregate

the issue of incremental energy rate valuation and hear the

matter prior to Phase II hearings.” (D.84-08-35, p. 4.)

In April 1984, the Commission issued an Order Instituting

Investigation (I.) 84-04-077 into the transmission system opera-

tions of the major electric utilities, in response to alleged trans-

mission constraints on PG&E’s transmission system which might

restrict the development of QFs in the northern portion of

PG&E’s service territory.

On October 17, 1984, the Commission issued D.84-10-098,

which suspended Payment Option No. 3 of SO 4 for PG&E for

QF projects over 50 MW, in response to reports from our Public

Staff and PG&E that a number of large oil and gas cogenerators

had signed or were anticipated to sign this offer. While we had not

imposed a MW limitation on the quantity of QFs which could

sign Payment Option No. 3, we had earlier recognized potential

problems:

“We recognize the benefits of having oil and gas cogener-

ators on the system to displace the units, but only to the

extent that: 1) cogeneration results in a more efficient use of

fossil fuels (i.e., the cogenerator’s actual incremental energy

rate is lower than the utility’s) and, 2) California’s resource

base, no matter how well it can be diversified, may require

some oil and gas generation units to meet demand. We are

concerned, however, that this energy payment option could,

over time, provide incentives to oil and gas cogenerators that

are not commensurate with the benefits described above.”

(D.83-09-054, pp. 44, 45.)

We ordered additional filings assessing how much of the

capacity signed under SO 4 with PG&E is likely to actually come

on line and how much additional capacity, particularly large

cogeneration projects, could be expected to sign contracts within a

year. We also set an en banc hearing for November 5, 1985 to

receive comments from PG&E, the Public Staff, and other

A-67

interested parties regarding the suspension of Payment Option 3.

We stated that:

“We intend to make any adjustments to Payment Option #3

as soon as possible so that any uncertainties aroused by

today’s actions will be short-lived. Therefore, this suspension

order will automatically expire on December 5, 1984 unless

the Commission issues an order outlining specific steps for

further action on this issue on or before that date.” (D.84-

10-098, p. 4.)

At the en banc hearings and through written comments as well,

parties were asked to respond to a motion of the Public Staff to

expand the suspension to include SO 2 and the remainder of SO

4, for projects over 50 MW. PG&E requested an even broader

suspension, of all of interim SO 4 and all of SO 2 for projects over

10 MW.

On December 5, 1984, the Commission issued a decision

extending the suspension to January 16, 1985, stating that:

“[ W]e conclude that the cornerstone for determining the

extent of QF capacity in PG&E’s service territory is the

adoption of a milestone procedure to mark the progress and

commitment of each QF project. It is clear that such steps

have not yet been taken by PG&E. Further, without such a

procedure it is difficult for this Commission or any other

party to verify the exact extent of the impact of QF develop-

ment on PG&E’s resource plan and its ratepayers.

“*[ W Je find that it is reasonable to continue the suspension of

Payment Option #3 of PG&E’s interim Standard Offer 4,

but coordinate any further expansion or removal of that

suspension with the milestone procedure to be considered in

1.84-04-077. We believe that a sufficient basis to maintain

the status quo has been presented by PG&E. We find,

however, that no further action is warranted until we have

had the opportunity to consider the comments and milestone

proposals to be presented during the public hearing sched-

uled for December 17, 1984 in J. 84-04-077.” (D. 84-12-027,

pp. 2, 3.)

A-68

In response to the Commission directive, a committee of

representatives from the Public Staff, the utilities, and QFs

prepared a milestone procedure designed as an interconnection

priority procedure (IPP), and presented it at the December 17

public hearing. On January 16, 1985, we adopted a slightly

modified version of the proposed IPP in D.85-01-038.

One of the modifications we required in the IPP was a new

requirement that PG&E, SCE, and SDG&E compile basic pro-

ject definition information on all QFs in their territories, through

mailing a questionnaire if needed, and that they file summaries of

the results by March 18, 1985. They have made the compliance

filings, and also supplemental filings providing more detail as

requested by the assigned Commissioner.

Also on January 16, we again extended the suspension of

Payment Option No. 3 of SO 4 for PG&E for QF projects over 50

MW. The Public Staff had recommended in a motion filed on

January 4, 1986 that the suspension be extended until “either

(a) 18 months plus a 20-day notice period from the date the

Interconnection Priority Procedure is adopted, or (b) the issuance

of a final decision on long-run avoided cost pricing [in this

proceeding].” (Pulbic Staff Motion, p. 10) In D.85-01-040, we

concluded that:

“We do not think that QF development is served by placing

the larger QFs ‘on hold’ for 18 months. Rather, we believe

that is our responsibility to maintain a continuing review of

QF development in PG&E’s service territory, especially in

light of the absence of any examination of estimates in an

evidentiary proceeding open to all interested parties.” (D.85-

01-040, p. 3)

Instead, we continued the suspension only until April 17, 1985,

to give us time to review the utility filings in compliance with the

adopted IPP.

On January 31, 1985, SCE filed a motion (SCE Motion)

seeking an emergency ex parte order providing a suspension of

Payment Option No. 3 of SO 4 in its territory comparable to that

in place for PG&E. Public Staff filed a response in support of

SCE’s motion and renewing its arguments in support of its

A-69

October 29, 1984 recommendation to suspend all payment op-

tions under interim SO 4 until adoption of a final SO 4. We

concluded, in D.85-02-069, that SCE is at some risk of having QF

energy supplies exceed its needs, and that it was reasonable to

grant the requested suspension until April 17, 1985. We stated

that, upon receipt of the IPP filings, we would review the

available information to determine the accuracy and verifiability

of the current estimates of QF development in both PG&E’s and

SCE’s service areas.

III. Discussion

The lengthy compilation of occurrences and Commission deci-

sions reiterated above shows the rather tortuous path leading to

today’s decision. As discussed below, we still do not have suffi-

cient information to feel absolutely confident that we have a good

grasp of likely QF development in California. However, much

more information is available now than at the time of our initial

actions last fall.

Questions which must be examined include:

1. How much of the signed QF capacity in each utility’s

service area is likely to come on-line and what is its likely impact

on system reliability?

2. Should the partial suspension of interim SO 4 lapse?

3. What would be the effects if interim SO 4 were suspended

until a final SO 4 is available?

4. Would a second negotiating conference be successful?

5. Are the capacity payments in SO 4 reasonable?

6. Are the energy prices in Payment Option No. | and

Payment Option No. 2 of SO 4 reasonable?

7. Are the incremental energy rates in Payment Option No. 3

of SO 4 reasonable?

We will address each of these issues in turn.

A-70 |

Viability and Effect of QF Projects with Signed Contracts

SCE asserts that it already has under contract 95 percent of the

QF capacity which it will need through 1994 (SCE Motion, p. 2).

PG&E claims that the capacity prices being offered in SO 4 are

substantially too high, mainly because of the unexpectedly large

number of QF contracts it has signed since the prices were

established.

Determination of the accuracy of PG&E’s and SCE’s asser-

tions is critical to our decision regarding whether to extend or

expand the existing suspension of a portion of interim SO 4. In

this section we examine the information available to us to assess

whether it supports PG&E’s and SCE’s positions. We also look at

comparable information for SDG&E, to determine whether ac-

tion regarding its interim SO 4 might also be warranted.

Table 1, Table 2, and Table 3 show, for PG&E, SCE, and

SDG&E respectively, the amounts of capacity which were opera-

tional, under contract, and under active discussion at the end of

1984 according to the Quarterly Status Reports which the utilities

file regularly with the Commission.’

' Quarterly Status Reports are required filings by prior order of this

Commission. For the purposes of this order, we take notice of the

Quarterly Status Reports filed for December 31, 1984.

Proj

A-71

TABLE I

Qualifying Facility Projects

Pacific Gas and Electric Company

December 31, 1984

Type

Cogeneration: (1)

Smaller than 25 MW....

25-49.9 MW

oeeeeeeewene

50 MW or larger .......

Solid Waste/ Biomass:

Cogeneration

Non Cogeneration ......

Geothermal

Pape «5...

SGeaan 84066 4 6 4

esevaeeaiese 8 #t6e

Sanh encen dase

@e00e8 2660280600

TOTAL EFFECTIVE

CAPACITY

Si tawen eee

(1) Fueled by other than

(Megawatts)

Under Under

Contract, Contract,

Operational Non-Operational

124 207

148 656

75 890

87 411

43 716

80 93

6 31

271 2024

107 624

l 0

942 5651

641 3534

solid waste/ biomass.

Under

Active

Discussion

118-199

473

2804

24

376

2

l

287

272

0

4462--4542

3800-3877

A-72

TABLE 2

Qualifying Facility Projects

Southern California Edison Company

December 31, 1984

(Megawatts)

Under Under

Contract, Contract,

Project Type Operational Non-Operational

Cogeneration: (1)

Smaller than 25 MW .... 159 3

25-499 WOW... e cae. 75 172

50 MW or larger......-- 55 1486

Solid Waste/Biomass...... 35 459

ee 15 411

ec oiagehed.s 15 107

Cs aun ee bens en 222 788

APP Prerr re rere. 72 36

ME Gk sa kk ab eens 648 3463

TOTAL EFFECTIVE

ae 5 ee 413 2418

(1) Fueled by other than solid waste/bicmass.

Under

Active

Discussion

105

175

420

272

85

36

1327

53

2474

1214

A-73

TABLE 3

Qualifying Facility Projects

San Diego Gas and Electric Company

December 31, 1984

(Megawatts)

Under Under Under

Contract, Contract, Active

Project Type Operational Non-Operational Discussion

Cogeneration: (1)

Smaller than 25 MW... 56 0 54

25-49.9 MW .......... 0 0 29

50 MW or larger....... 0 0 0

Solid Waste/Biomass..... 0 47 75

3 sa veda aw anas 0 0 0

Seer partie one a 5 2 17

WE Sas caretevebesakss 3 0 4

PE cak keskadeenaencs 2 0 8

Wen os bk bad cae vk 76 49 188

TOTAL EFFECTIVE

4 3 y See 62 42 154

(1) Fueled by other than solid waste/biomass.

PG&E has almost 2,200 MW more QF capacity under contract

but not yet operational than does SCE (5,651 MW compared to

3,463 MW). However, over 80 percent of this difference is

attributable to the larger amounts of wind and hydro capacity

which PG&E has under contract. Because of the expected lower

capacity factors during peak periods of as-available capacity, the

nameplate capacities of such projects must be discounted signifi-

cantly for system planning purposes. PG&E has only about 1,100

MW more “effective” capacity (as defined in Appendix A) under

contract than does SCE. Because of the importance of consider-

ing effective capacity rather than nameplate capacity, we present

much of the analysis in this section in terms of effective capacity.

As made clear by Table 3, QF activity is much less pronounced

in SDG&E’s area than for the other two utilities. SDG&E has

projects totalling only about 42 MW of effective capacity under

contract but not yet operational, and only about 150 MW of

effective capacity under discussion.

A-74

As mentioned above, the utilities have also filed information

regarding the status of non-operational QF projects which re-

sponded to the questionnaires mailed at our direction. Responses

to some of the more pertinent questions by QFs which have

signed contracts are summarized in Table 4. For PG&E, informa-

tion is also presented for those projects not on transmission

waiting lists in the northern portion of PG&E’s territory or in the

Altamont Pass area. This is important because many of the

projects on the two waiting lists may proceed only if other projects

with transmission priority do not go forward or PG&E builds the

necessary transmission upgrades.

TABLE 4

Comparison of Responses

To Project Questionnaire

Of Projects with Signed Contracts

(Percent of Effective Capacity Responding)

PG&E SCE SDG&E

Not on

Waiting

All =— Lists

1. Critical Path Permits Applied for .. 47% 47% 66% 100%

2. Critical Path Permits Received ... 30% 36% 35% 4%

3. All or Portion of Financing Secured 43% 39% 40% 100%

4. Generating Equipment Ordered ... 17% 14% 26% 0%

5. Project Construction Begun ....... 16% 20% 19% 0%

PUD. GT TRIED ove ccccccscececesas 206 125 61 5

Effective MW of Responses........... 2,091 1,436 1,895 8

No. of Signed Contracts

CED onus scasdadawsedcos 308 115 10

Effective MW of Signed Contracts

CU ncccetsedesndsesenues . 3,534 2,418 42

As can be seen, there was significant variation in the response

rates to the questionnaires. SCE had a much larger response rate

in terms of effective capacity under contract (78 percent) than

did either PG&E (59 percent) or SDG&E (19 percent). This

disappointing response reduces the credibility of the results. It is

not clear whether those QFs which responded are representative

of the other QFs.

A-75

We have hoped that the survey results would shed some light

on the commonly held belief that projects signed by SCE are

more likely to come on line than those signed by PG&E. If the

responses can be viewed as reasonably representative of all QFs,

then Table 4 supports this thesis, but only weakly. While a larger

percentage of projects in SCE’s area have applied for their critical

path permits, about the same percentage of projects which re-

sponded to the questionnaires have received their permits in the

two areas. Similary, while a larger percentage of projects in SCE’s

area say that they have ordered their generating equipment, about

the same percentage in both areas are under construction.

Another measure of whether PG&E’s signed capacity should

be viewed as seriously as SCE’s is the number of earlier contracts

which have been cancelled. PG&E’s December 31, 1984 Quar-

terly Status Report reveals that 21 signed projects with a total

effective capacity of about 100 MW have “terminated.” At the

assigned Commissioner’s request, SCE has informed us (see

letter attached as Appendix B) that 5 signed projects have

cancelled their contracts with SCE. ‘rheir total effective capacity

is about 137 MW. PG&E’s failed projects include 13 very small

wind, hydro, or photovoltaic QFs totalling about 50 kilowatts in

effective capacity, whereas the cancellation reported by SCE

include only two projects under | MW. Excluding the very small

projects, we conclude that the record of cancelled contracts

indicates, if anything, that PG&E has been the more successful of

the two utilities.

At the request of the assigned Commissioner, our staff has

provided calculations of the effect of the existing signed QF

Capacity on the reserve margins and on the value of additional QF

capacity for PG&E and SCE.’ Those calculations, which are

presented in detail in Appendix A, indicate that PG&E is likely to

have much larger reserve margins through the late 1980s and

early 1990s than SCE.

* While these calculations were performed by members of the Public

Staff Division (PSD), the results and the use we make of them do not in

any way represent the position of the PSD. The provision of these

calculations at the request of the assigned Commissioner does not

prejudice PSD’s position as an independent party in these proceedings.

a

A-76

In this analysis, PG&E’s and SCE’s nameplate signed capacity

is translated into effective available peak capacity. Three scena-

rios are then created, representing development of 80 percent, 50

percent, and 30 percent, respectively, of the effective QF capacity

under contract but not yet operational.

We realize that the probability that only 30 percent of QFs

under contract will materialize is fairly low. We prefer to view the

three scenarios as three versions of potential need for additional

QF capacity. Thus, the 30 percent scenario would present a

greater need for additional QF capacity, which could occur if, in

addition to QF development being low, demand growth is higher

than projected or utility plants such as Diablo, Helms, or San

Onofre operate at low capacity factors.’ The 80 percent scenario

reflects lower need for additional QF capacity, which could occur

if most of the signed projects come on-line, if demand growth is

low, and/or if utility plants operate better than expected.

PG&E’s and SCE’s reserve margins through 1995 under the 80

percent and 30 percent scenarios are shown in Figure |. The

difference is striking. Under even the scenario of development of

30 percent of signed contracts (or the equivalent effect on reserve

margins due to factors such as higher load growth), PG&E’s

reserve margin remains above 27 percent through 1992, though it

falls to 18 percent by 1995. If the 80 percent scenario occurs,

PG&E’s reserve margin could peak at 49 percent in 1989 and still

be 27 percent in 1995. By contrast, even if 80 percent of SCE’s

signed QF contracts produce operating projects, its reserve mar-

gin would reach a high of only 26 percent in 1988, dropping to 13

percent by 1995. Under the more pessimistic scenario of 30

percent QF development, SCE’s reserve margin would remain at

about 20 percent through 1988, but then falling rapidly to critical

levels, reaching less than 17 percent by 1995.

For example, the need for additional QF capacity under the 30

percent scenario for PG&E corresponds roughly to development of 80

percent of signed QF capacity coupled with annual load growth through

1992 of 3.2 percent (rather than the 1.4 percent assumed in the

calculations shown in Appendix A).

Reserve Margin (Percent)

50% ,

4 Y a |

7 i: |

Ps ~

i ~~, |

40% — ~< —

, = *o |

ALT ine sng |

oe ~ = |

30% < mo SN )

+oGe ‘4

” tig re, | |

20% Sa —™ See. —~—

s |

10% eee aa

ae

O%

1985 1987 1989 1991 1993 1995

Figure |] PG&E and SCE Reserve Margins with High and low Levels

of OF Development

We recognize that this analysis is somewhat simplistic. How-

ever, it does provide useful insight into the situation at hand. It

appears fairly unlikely that PG&E will fall seriously short of

capacity through the next decade even though additional QF

capacity could enhance system reliability somewhat. Given the

uncertainty surrounding QF development and other factors such

as load growth, we conclude that SCE is premature in asserting

that it needs only 158 MW of additional QF capacity through

1994 (SCE Motion, Table 1).

Should the Partial Suspension of Interim Standard Offer 4

Lapse?

In establishing interim SO 4, we expected that it would be in

effect for only a short while. Because of concerns we had about

both the levelized energy price option (Payment Option No. 2)

A-78

and the incremental energy rate option (Payment Option No. 3),

we initially made them effective for only one year. At the time we

extended these options in August 1984, we still did not foresee

any serious problems with the overall payment levels, and ex-

pected that the terms of iiterim SO 4 would remain in effect until

a final SO 4 became available.

Since last August, rapid changes in the QF market have

outstripped the pace of our regulatory process. We have already

imposed partial suspensions of interim SO 4 for PG&E and, later,

for SCE. Now we must decide whether the suspension should be

allowed to lapse, or whether other action is needed.

While SCE and, to a lesser extent, PG&E still have some need

for additional capacity, the reserve margins for each utility under

even the worst case scenario examined are high enough to

indicate that the capacity payments in interim SO 4 (which are

those which were offered in SO | and SO 2 at the time of the

negotiating conference) may now overvalue new QF capacity.

Comparable calculations were not made for SDG&E, because

it has not asserted that too many QF projects are signing contracts

to sell power to SDG&E. We are concerned, however, about

whether its prices being offered under interim SO 4 are too high.

Even if only a limited number of QF projects are developed in

SDG&E’s region, if the payments are too high then ratepayer

indifference is no longer maintained.

In Application (A.)82-12-57, SDG&E’s 1984 general rate

case, SDG&E proposed reductions in the capacity payments

available to QFs in its SO | and SO 2, based on its forcecast of

the probability of need for additional capacity. We adopted these

adjustments in D.83-12-065 as reasonable. Since the capacity

payments which had been in effect for SO 1 and SO 2 prior to

D.83-12-065 were equal to the capacity payments which are still

in interim SO 4, we conclude, based on D.83-12-065, that they

are too high for interim SO 4 as well.

The capacity payments must not be looked at in isolation,

however. In deciding whether the terms of a proffered contract

are acceptable, a third party undoubtedly looks at energy and

capacity payments as a package. We recognized in D.84-08-035,

A-79

in considering whether the incremental energy rates in Payment

Option No. 3 should be modified, that a change in one term of an

interim SO 4 contract would require the reexamination of other

components as well. Thus, in an assessment of what changes, if

any, are appropriate for the capacity payments in interim SO 4,

the energy payment component must be considered as well.

It is obvious that significant changes have occurred in the

energy markets since the negotiating conference was held in June

1983. Natural gas prices have stabilized and even fallen, and

further reductions are quite possible. In Table 5, the incremental

costs of natural gas to PG&E, Southern California Gas Company

(SoCal), and SDG&E are shown. PG&E and SDG&E have

experienced substantial price reductions in the last 20 months,

and if the effects of inflation were removed, Table 5 would show

that SoCal’s incremental cost of gas has also decreased, in real

terms. There are at least two other easily available comparisons

which provide a measure of changes in the utilities’ avoided

energy prices: The rates which utilities pay for natural gas for use

in their own generating units (Table 6) and the avoided costs

prices paid to QFs operating with short-run standard offer con-

tracts. (Table 7). Natural gas rates for electric generation have

declined for all three utilities, from 2 percent to 17 percent. SCE’s

and SDG&E’s short-run avoided cost energy payments have

declined substantially, by 11 percent and 15 percent respectively.

PG&E’s energy payments have increased dramatically, due to

higher incremental energy rates adopted in its December 1983

general rate case decision. However, as pointed out in Table 7

(see also Table 14), that rate case decision also authorized

PG&E to reduce its short-run avoided cost energy payments

about 20 percent after Diablo | and Diablo 2 become commer-

cially operable. At current gas prices, these payments would be

reduced to about 5.4 cents per kilowatt-hour, which is about 7

percent less than the June 1983 level.

A-80

TABLE 5

Incremental Costs of Gas

(Cents per therm)

June April

1983 1985 Change

Poe Beda hak An CaAe SO kee 32.7 29.1 —11%

va sb 5a oa es hak Nae hema rer 3, 32.8 +0.3%

MR. 3s x co N 434 04D Keke Sasa eee 41.5 35.5 —14%

TABLE 6

Natural Gas Rates

For Electricity Generation

(Cents per therm)

June April

1983 1985 Change

a rrr ere gen) 53.50 52.45 - ie

ME vaca ho Nie i wbie xide kd See 46.33 45.44(1) =— £2

CE cen sis neu eekaehkaweaae 55.00 46.99 —-17%

(1) Weighted average of episode and non-episode day rates.

TABLE 7

Non-Time Differentiated

Avoided Cost Energy Payments

(cents per kilowatt-hour)

June April

1983 1985 Change

ee 5.8 7.2(1) +24% (—7%) (1)

ee 4.6 4.1 —11%

RE er 6.2 5.3 —15%

(1) PG&E’s energy payment will be reduced by about 13 percent afier

Diablo | becomes commercially operable and an additional 8

percent after Diablo 2 becomes commercially operable. At current

G-55 rates the energy payment would average 5.4 cents per kilo-

watt-hour after Diablo | and Diablo 2 become commercially

operable.

Sib ENT acne Celt dite Belated,

A-81

While we do not know what energy price forecasts were relied

upon by the parties to the negotiating conference, we suspect that

they did not predict the current turn of events. Thus, the energy

components of interim SO 4 may be overstated. The rapid rate at

which PG&E and SCE have signed interim SO 4 contracts

indicates that the overall pricing terms, including both capacity

and energy provisions, may be seen as very favorable by QFs.

If significant amounts of additional QF projects are allowed to

sign contracts with the prices currently offered, ratepayers may

indeed, as PG&E, and SCE assert, be required to pay more for

the capacity and electricity than is reasonable. Because of this

possibility, we agree with PG&E, SCE, and our staff that some

action must be taken to protect ratepayers. The partial suspension

cannot merely be allowed to lapse.

Possible Effects of a Suspension of Interim Standard Offer 4

From our viewpoint, continuation and expansion of the current

limited suspension of interim SO 4 might be the easiest regulatory

response to the current situation. It would require a minimum of

staff resources and minimal delay in the Phase II hearings on the

long-run avoided cost methodology. Since the utilities appear to

be in no imminent danger of capacity shortfalls, a complete

suspension might protect ratepayers while the final long-run

standard offer is being developed.

Public Staff has repeatedly supported action along these lines.

On October 29, 1984, PSD requested that PG&E’s suspension be

expanded to include SO 2 and the remainder of SO 4, for projects

over 50 MW. On January 4, 1985 PSD recommended that the

suspension be extended about 19 months, to allow time to

ascertain how much of the QF capacity now under contract will

materialize. or until the issuance of a final decision on long-run

avoided cost pricing. Most recently, in its response to SCE’s

motion requesting suspension of Payment Option No. 3 for

projects over 50 MW in its territory, PSD recommended suspen-

sion of all payment options of interim SO 4 until a final SO 4 is

adopted, unless prices are adjusted to reflected current conditions

through another interim Commission order.

A-82

In informal discussions, a number of other parties have also

seemed agreeable to this approach. Other parties, most notably

QFs negotiating contracts with the utilities, do not support contin-

uation or expansion of the suspension.

We see several potential problems with a significant expansion

of the current suspension. First, despite any amount of reassur-

ances which we could make to the contrary, it might be viewed by

QFs and the financial community as a reduction in our commit-

ment to the development of the QF industry. That view certainly

would not be accurate.

Second, some QF projects which are under consideration and

which may be in ratepayers’ best interests in terms of meeting

future energy needs may not be able to survive a lengthy suspen-

sion of the availability of standard offer contracts. We realize that

many QFs could wait until a final SO 4 is approved, and others

might successfully enter into negotiations of non-standard con-

tracts with the utilities to allow their projects to proceed this year.

This brings us to another concern. One of the benefits of the

standard offers is that they provide reasonable back-up alterna-

tives to QFs who want, for whatever reason, to negotiate non-

standard contracts. They provide a measure of the reasonableness

of the utility’s negotiations and an alternative if negotiations do

not yield terms acceptable to both the QF and the utility.

Suspending the standard offers would remove this safeguard.

Further, the very action of suspending the standard offers for a

significant period of time could be viewed by the utilities as a

signal that the Commission might look unfavorable upon non-

standard contracts signed in the interim unless the contract terms

are significantly below the present standard offers. This response

would not be surprising, since we would essentially be concluding

that the existing yardstick is no longer reasonable.

While expansion of the suspension has been presented as an

easy solution which would not require staff time or delay develop-

ment of the final long-run standard offer, it may not be so simple.

We have already had to address requests from QFs to allow

switching to the interim SO 4 offer. It is easy for us to imagine

that other QFs would similarly ask for special consideration if the

A-83

offer were completely suspended. We would confront the Hob-

son’s choice to either devote the staff resources needed to evaluate

such requests, or allow absolutely no exceptions to the suspension.

It has been suggested that there may not be significant amounts

of QF capacity which would want to sign contracts in the next

year or so, in effect that the “gold rush” effect that appears to

have occurred in recent months may have already resulted in the

signing of contracts for almost all QF projects which were being

considered by potential developers. The utilities’ Quarterly Status

Reports appear to refute this possibility. As summarized earlier in

Table | and Table 2, PG&E is in active discussion with potential

QF projects totalling over 4,500 MW; developers of projects

totalling over 2,400 MW are discussing contracts with SCE.

Rather than expand the suspension, we could simply e

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