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					                                                            [Draft: (San Francisco) April 15, 1999]


                     BEFORE THE PUBLIC UTILITIES COMMISSION
                          OF THE STATE OF CALIFORNIA



      Order Instituting Rulemaking into
      Implementation of Pub. Util. Code § 390.       Rulemaking 99-11-022




                             PHASE 1 OPENING BRIEF OF
                      THE CALIFORNIA COGENERATION COUNCIL
                       AND WATSON COGENERATION COMPANY




                                                 Joseph M. Karp
                                                 White & Case LLP
                                                 Two Embarcadero Center, Suite 650
                                                 San Francisco, CA 94111
                                                 Telephone: (415) 544-1100
                                                 Facsimile: (415) 544-0202

                                                 Attorneys for the California
                                                 Cogeneration Council and Watson
                                                 Cogeneration Company

      June 1, 2000



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                                                  TABLE OF AUTHORITIES



      Commission Decisions
      D.86-05-024 .......................................................................................................................30
      D.87-12-066 .......................................................................................................................30
      D.88-03-079 .......................................................................................................................34
      D.88-11-052 .......................................................................................................................34
      D.92-03-022 .......................................................................................................................37
      D.92-05-022 .......................................................................................................................37
      D.92-08-040 .......................................................................................................................37
      D.92-09-038 .......................................................................................................................37
      D.93-01-040 .......................................................................................................................37
      D.93-02-015 .......................................................................................................................37
      D.93-03-046 .......................................................................................................................37
      D.93-10-071 .......................................................................................................................37
      D.94-02-016 .......................................................................................................................37
      D.94-04-040 .......................................................................................................................37
      D.94-09-035 .......................................................................................................................37
      D.95-01-003 .......................................................................................................................37
      D.95-02-019 .......................................................................................................................37
      D.95-04-004 .......................................................................................................................37
      D.95-06-050 .......................................................................................................................37
      D.95-09-117 .......................................................................................................................37
      D.95-10-021 .......................................................................................................................37
      D.95-12-063, as modified by D.96-01-009 ........................................................................23
      D.96-07-023 .......................................................................................................................37
      D.96-07-026 .......................................................................................................................37
      D.96-10-036 .................................................................................................................29, 47
      D.98-09-042 .......................................................................................................................37
      D.99-03-021 ...........................................................................................................49, 51, 56

      California State Court Decisions
      Northern California Power Agency v. California Public Utilities Commission, 5 Cal. 3d
        370..................................................................................................................................11
      Reese v. Kizer, 46 Cal. 3d 996 (1988)................................................................................26

      Federal Regulations
      18 CFR 292.101 .................................................................................................................19
      18 CFR 292.304 .................................................................................................................19
      18 CFR 292.305 .................................................................................................................49

      California State Constitutional Provisions
      Cal. Const. art III, § 3.5(c) .................................................................................................26



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      FERC Decisions
      82 FERC 61,126.................................................................................................................11
      82 FERC 61,295.................................................................................................................11
      83 FERC 61,317.................................................................................................................11

      Federal Court Decisions
      American Paper Institute, Inc. v. American Electric Power Service Corp., 461 U.S. 401
        (1982) .............................................................................................................................19
      Delta Dental Plan of Cal., Inc. v. Mendoza, 139 F.3d 1289 (9th Cir. 1998) .....................26




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                                  SUMMARY OF RECOMMENDATIONS

      A.           Functioning Properly Criteria

                         The Commission should adopt, as criteria for determining whether the PX
                          is functioning properly for the purposes of determining SRAC payments to
                          QFs, the following five general standards:

                          (i)     The PX should reflect open and fair competition and be free from
                                  distortions caused by undue market power by either buyers or
                                  sellers.

                          (ii)    The PX should have adequate liquidity.

                          (iii)   The PX should have adequate demand responsiveness.

                          (iv)    The PX should have transparent pricing.

                          (v)     There should be adequate market oversight and monitoring.

                         The Commission also should adopt the following five specific criteria to
                          determine whether the PX in fact meets the general standards for market
                          power, liquidity and demand responsiveness:

                          (i)     For buyer or seller HHIs above 1,800, the Commission should
                                  require substantial evidence that such concentration does not
                                  impair the proper functioning of the PX market.

                          (ii)    The ISO must have significantly raised or eliminated the current
                                  price caps in the real-time market (possibly retaining “safety net”
                                  or “damage control” price-cap authority).

                          (iii)   The day-ahead PX and real-time ISO market prices should have
                                  averaged within 20% of each other during peak demand hours.

                          (iv)    The PX day-ahead market clearing price should be zero in no more
                                  than one percent of the hours in the immediately preceding twelve-
                                  month period.

                          (v)     The rate freeze must have ended.

      B.           SRAC Energy Pricing

                         The Commission should adopt CCC/Watson‟s proposal to set SRAC
                          energy payments equal to the day-ahead PX price for the zone in which the
                          QF is located, less the value of capacity in the PX price as determined in


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                          accordance California Public Utilities Code Section 390(d).

                         The Commission should reject the Edison/ORA “new market entrant”
                          SRAC proposal.

                         The Commission should reject ORA‟s proposed “heat rate cap” SRAC
                          proposal.

                         The Commission should reject ORA‟s proposed SRAC payment
                          subtractors.

                         The Commission should require an annual comparison of PX prices to a
                          “basket” of other market price indicators and require each utility to report
                          on the sources of their energy procurement in order to track whether the
                          PX day-ahead price continues to reflect the utility‟s avoided cost; the
                          Commission should reconsider the SRAC pricing methodology upon the
                          motion of a party demonstrating the need for such reconsideration.

      C.           As-Available Capacity Pricing

                         The Commission should adopt the CCC‟s proposal to set as-available
                          capacity payments for Edison and SDG&E QFs equal to the simple
                          average of the prices for spinning reserves and non-spinning reserves as
                          determined by the ISO.

                         The Commission should adopt the CCC‟s proposal to set as-available
                          capacity payments for PG&E QFs equal to the value of capacity in the PX
                          price as determined in accordance with Section 390(d).

      D.           Line Loss Factors

                         The Commission should adopt the CCC‟s proposal to base the
                          transmission-level line loss factor upon “unscaled” GMM data.

                         The Commission should adopt the CCC‟s proposal to establish a unique
                          transmission-level line loss factor, also based upon unscaled GMM data,
                          for QFs that are remote from the load centers to the extent that they serve
                          local load.




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                         BEFORE THE PUBLIC UTILITIES COMMISSION
                              OF THE STATE OF CALIFORNIA



Order Instituting Rulemaking into
Implementation of Pub. Util. Code § 390.                       Rulemaking 99-11-022



                                 PHASE 1 OPENING BRIEF OF
                          THE CALIFORNIA COGENERATION COUNCIL
                           AND WATSON COGENERATION COMPANY


I.          Introduction.
            Pursuant to Rule 75 of the Rules of Practice and Procedure of the California Public
Utilities Commission (“Commission”), the California Cogeneration Council (“CCC”) and
Watson Cogeneration Company (“Watson”) submit this Opening Brief in above-referenced
proceeding. In this brief, the CCC and Watson (jointly “CCC/Watson”) explain why the
Commission should adopt the CCC‟s and Watson‟s proposals for determining short-run avoided
cost (“SRAC”) payments to qualifying facilities (“QFs”) under the Public Utility Regulatory
Policies Act of 1978 (“PURPA”) and Section 390 of the California Public Utilities Code
(“Section 390”).1

            In particular, this brief sets forth detailed legal and evidentiary support for the following
CCC/Watson proposals.




________________________

1
       Watson takes no position on functioning properly criteria, as-available capacity pricing and
       line loss factors.




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A.          Functioning Properly Criteria

                  The Commission should adopt, as criteria for determining whether the California
                   Power Exchange (“PX”) is functioning properly for the purposes of determining
                   SRAC payments to QFs, the following five general standards:

                   (i)     The PX should reflect open and fair competition and be free from
                           distortions caused by undue market power by either buyers or sellers.

                   (ii)    The PX should have adequate liquidity.

                   (iii)   The PX should have adequate demand responsiveness.

                   (iv)    The PX should have transparent pricing.

                   (v)     There should be adequate market oversight and monitoring.

                  The Commission also should adopt the following five specific criteria to
                   determine whether the PX in fact meets the general standards for market power,
                   liquidity and demand responsiveness:

                   (i)     For buyer or seller HHIs above 1,800, the Commission should require
                           substantial evidence that such concentration does not impair the proper
                           functioning of the PX market.

                   (ii)    The California Independent System Operator (“ISO”) must have
                           significantly raised or eliminated the current price caps in the real-time
                           market (possibly retaining “safety net” or “damage control” price-cap
                           authority).

                   (iii)   The day-ahead PX and real-time ISO market prices should have averaged
                           within 20% of each other during peak demand hours.

                   (iv)    The PX day-ahead market clearing price should be zero in no more than
                           one percent of the hours in the immediately preceding twelve-month
                           period.

                   (v)     The rate freeze must have ended.

B.          SRAC Energy Pricing

                  The Commission should adopt CCC/Watson‟s proposal to set SRAC energy
                   payments equal to the day-ahead PX price for the zone in which the QF is located,




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                   less the value of capacity in the PX price as determined in accordance with
                   Section 390(d) of the California Public Utilities Code (“Section 390(d)”).2

                  The Commission should reject the Southern California Edison Company
                   (“Edison”)/Office of Ratepayer Advocates (“ORA”) “new market entrant” SRAC
                   proposal.

                  The Commission should reject ORA‟s proposed “heat rate cap” SRAC proposal.

                  The Commission should reject ORA‟s proposed SRAC payment subtractors.

                  The Commission should require an annual comparison of PX prices to a “basket”
                   of other market price indicators and require each utility to report on the sources of
                   their energy procurement in order to track whether the PX day-ahead price
                   continues to reflect the utility‟s avoided cost; the Commission should reconsider
                   the SRAC pricing methodology upon the motion of a party demonstrating the
                   need for such reconsideration.

C.          As-Available Capacity Pricing

                  The Commission should adopt the CCC‟s proposal to set as-available capacity
                   payments for Edison and San Diego Gas & Electric Company (“SDG&E”) QFs
                   equal to the simple average of the prices for spinning reserves and non-spinning
                   reserves as determined by the ISO.

                  The Commission should adopt the CCC‟s proposal to set as-available capacity
                   payments for Pacific Gas and Electric Company (“PG&E”) QFs equal to the value
                   of capacity in the PX price as determined in accordance with Section 390(d).

D.          Line Loss Factors

                  The Commission should adopt the CCC‟s proposal to base the transmission-level
                   line loss factor (“TLF”) upon “unscaled” Generation Meter Multiplier (“GMM”)
                   data.

                  The Commission should adopt the CCC‟s proposal to establish a unique TLF, also
                   based upon unscaled GMM data, for QFs that are remote from the load centers to
                   the extent that they serve local load.

________________________

2
       As discussed further below, CCC/Watson also propose an alternative SRAC energy pricing
       mechanism which may be employed in lieu of the CCC‟s proposed price
       convergence criterion.




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II.         Discussion.
            A.     Functioning Properly Criteria.
                   1.     Introduction and Summary.
            Section 390(c) provides, in relevant part, that SRAC energy payments shall be based
upon the PX clearing price, if “the commission has issued an order determining that the
independent Power Exchange is functioning properly for the purposes of determining the short-
run avoided cost energy payments . . .” for QFs. Until the finding referred to in Section 390(c) is
made, SRAC energy payments are to be determined in accordance with the formula specified in
Section 390(b) of the California Public Utilities Code.3

            Both the Commission‟s order instituting this Rulemaking 99-11-022 (“Rulemaking”) and
the subsequent Scoping Memo provide that the Commission will develop in this phase of the
proceeding the criteria for determining whether the PX is functioning properly within the
meaning of Section 390(c). See, e.g., Rulemaking at 14, Scoping Memo at 1. The Rulemaking
and Scoping Memo reserve to Phase 2 of this proceeding the application of the adopted criteria to
determine if indeed the PX is functioning properly. See, e.g., Rulemaking at 14, Scoping Memo
at 2. Thus, although a few parties submitted testimony addressing the ultimate question of
whether the PX is, at the present time, functioning properly, the relevant “functioning properly”
issue for the Commission in this phase of the proceeding involves, exclusively, setting the
criteria that will be used later to determine whether the PX is functioning properly.

            The CCC, Independent Energy Producers Association (“IEP”), ORA, Edison, SDG&E,
PG&E, the PX, and Automated Power Exchange (“APX”) presented testimony on functioning
properly criteria. Generally speaking, there was a broad consensus with respect to five
underlying principles or standards that should govern the Commission‟s functioning properly
inquiry in Phase 2. These standards are discussed immediately below, and should be adopted by

________________________

3
       Section 390(c) also requires that one of two other conditions be met prior to the transition to
       PX-based SRAC.




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the Commission as the underlying requirements of a properly functioning PX. In addition, the
CCC proposes five specific criteria that would serve as actual tests that the Commission can
employ in Phase 2 to determine whether three of these general standards are, in fact, met. The
Commission should adopt these specific criteria for a properly functioning PX as well.

                   2.     The Commission should adopt the following five general standards as
                          underlying criteria for determining whether the PX is functioning
                          properly.
                          (i)     The PX should reflect open and fair competition and be free from
                                  distortions caused by undue market power by either buyers or
                                  sellers.
            There is near unanimity among the parties that the PX should produce competitive prices,
free from distortions caused by the exercise of undue market power. Absent a PX that reflects
competitive market prices, the Commission cannot be confident that the PX market clearing price
will reflect the utilities‟ short-run avoided costs; rather, the PX may reflect prices that are
artificially higher or artificially lower than SRAC. As a result, absent a competitive PX market
that is free from the influence of undue market power, the PX cannot be considered to be
“functioning properly” for SRAC purposes. Of critical importance is that the Commission
consider the exercise of market power by both buyers and sellers, for undue exercise by either
can distort the PX price.

            CCC witness Beach, for example, testified that the PX must be “workably competitive for
both buyers and sellers,” and proposed a number of specific criteria, discussed below, to discern
whether the market is workably competitive and free from undue market power. CCC/Beach,
Ex. 3, at 8:4-6, 9:9-21:14. Edison witness Stern likewise testified that “[n]either seller nor buyer
market power should exist such that the market price deviates from short-run avoided costs.”
Edison/Stern, Ex. 50, at 15:15-16. ORA witness Linsey also testified that, in order to be
functioning properly, the PX must deliver “competitive results” and that “market power must be
no more than a sporadic and not a sustainable occurrence.” ORA/Linsey, Ex. 100, at 6:5-6, 7:19-
20. See also, SDG&E/Schelhorse, Ex. 51, at 3:6-7 (“Neither seller nor buyer market power
should cause undue distortions in the market price . . . .”); PG&E/Pappas, Ex.52, at 2, 3 (stating
that “the PX‟s market-clearing price must accurately reflect the competitive price for energy in


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the new marketplace . . .” and expressing concern that “any individual participant [be able] to
exert market power); IEP/Branchcomb, Ex. 4, at 3-4 (proposing to analyze PX readiness in
accordance with the standards for a “perfectly competitive commodity market,” but recognizing
that workable competition is the norm). Finally, APX witness Cazalet, although not so focused
on market power, testified that the PX must “reflect an efficient forward market which minimizes
impediments to trading” and must be a “competitive market.” APX/Cazalet, Ex. 150,
at 6:28-31.

            Of all the parties commenting on the functioning properly issues, only PX witness
Kritikson was critical of the competitiveness/market power standard. Drawing a distinction
between concerns affecting the PX itself and concerns affecting the broader functioning of the
electricity market in California, Mr. Kritikson does not believe that either the level of
competitiveness in the market or the amount of market power exercised should be criteria
employed by the Commission in this proceeding. These issues, assert Mr. Kritikson, are
concerns with the proper functioning of the broader electricity market, and do not bear on
whether the PX is functioning properly. PX/Kritikson, Ex. 153, at 1-2, 9-10. Mr. Kritikson‟s
distinction, however, is not meaningful for purposes of this proceeding. Whether the PX itself is
flawed and yielding distorted prices, or whether there are problems in the broader power market
in California that distort the prices published by the PX, it is all one and the same. Under either
of these circumstances, the PX market clearing price is not reflecting the utilities‟ SRAC and the
Commission should find that the PX is not functioning properly for the purpose of determining
SRAC payments to QFs.

            Mr. Kritikson admitted as much on cross-examination.

                   Q. If you would assume that through the exercise of market power, the
                   investor-owned utilities could deflate the PX price in order to reduce
                   SRAC payments to QFs . . . [w]ould you think that the Commission
                   should, in that circumstance, find that the market is functioning properly
                   for SRAC purposes?

                   A. I would think that if the Commission found that the – there was market
                   power being exercised on either side of the market supply or demand to
                   cause the price to go down for a substantial number of hours in the market,
                   the Commission might have difficulty finding that the market was

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                     workably competitive.

                     Q. So the exercise – the exercise of market power is an important factor
                     for the Commission to consider in determining whether the market‟s
                     functioning properly, correct?

                     A. I would think it is a factor the Commission would take into account.

PX/Kritikson, Tr. 799:16-800:8. As such, even according to Mr. Kritikson, the Commission
should consider the level of competition and exercise of market power in the PX as part of its
determination as to whether or not the PX is functioning properly for SRAC purposes.

                            (ii)   The PX should have adequate liquidity.
            The parties generally agree that there must be adequate liquidity in the PX market. CCC
witness Beach, for example, testified that the “PX market must be „thick‟ and liquid enough to
function properly.” CCC/Beach, Ex. 3, at 18:5-6. Edison witness Stern likewise testified that
“there must be adequate liquidity in the market such that the price reflects market conditions.
Edison/Stern, Ex. 50, at 15:13-14. See also PG&E/Pappas, Ex.52, at 3 (“Markets must be liquid
with prices reflecting competitive supply and demand conditions.”); SDG&E/Schelhorse, Ex. 51,
at 3:4-5 (“There should be adequate liquidity in the market such that the price reflects market
conditions”); IEP/Branchcomb, Ex. 4, at 3 (“[The market must have] [n]umerous buyers and
sellers . . . .”).

            While agreeing that “liquidity is an important feature of a reliable and efficient market,”
PX witness Kritikson “would urge caution in considering this feature as a criterion . . .” because,
according to Mr. Kritikson, liquidity is difficult to measure. PX/Kritikson, Ex. 153, at 7. The
CCC does not necessarily disagree with Mr. Kritikson that “liquidity,” in and of itself, may be
less than a precise standard. Nevertheless, as Mr. Kritikson admits, liquidity is an essential
underpinning to a competitive market and the Commission should consider it as a necessary
element of the properly functioning PX. As discussed below, the Commission should adopt the
specific measures of liquidity proposed by the CCC to translate this general standard into criteria
that can actually be applied in Phase 2 of this proceeding.




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                           (iii)   The PX should have adequate demand responsiveness.
            The parties also generally concur that there must be adequate demand responsiveness in
the market. As CCC witness Beach testified: “One common theme in virtually all assessments
of the performance of the California electric markets is the critical need to introduce more price
responsiveness into end-use demand.” CCC/Beach, Ex. 3, at 19:15-17. Similarly, Edison
witness Stern testified: “One of the principal assumptions underlying an efficient, and therefore
„properly functioning‟ market is that both supply and real demand bids clear the market. The PX
was designed to operate in this manner.” Edison/Stern, Ex. 50, at 17:6-8 (emphasis original).
ORA witness Linsey testified that demand bidding “should play a genuine and robust role in
determining the market price.” ORA/Linsey, Ex. 100, at 12:5-7. See also PG&E/Pappas, Ex.52,
at 4 (“Markets prices must be based on available demand and supply bids.”);
SDG&E/Schelhorse, Ex. 51, at 3:1-2 (“The market clearing price should be based on the bids of
available demand and supply.”)

            Once again, only PX witness Kritikson does not believe that price sensitivity of demand
should be a criterion, as he believes that price sensitivity of demand is a concern with the broader
electricity market. PX/Kritikson, Ex.153, at 8. As discussed above, Mr. Kritikson‟s distinction
between PX problems and problems in the broader market has no merit. If, as a result, of
insufficient demand responsiveness, the PX market clearing price does not reflect SRAC, the PX
cannot be said to be functioning properly. In addition, Mr. Kritikson bases his position on
demand responsiveness in large part upon his belief that after the utilities‟ rate freezes end
changes in retail prices will correspond with changes in wholesale prices, and that other steps are
being taken to increase demand responsiveness. Id. at 8-9. Whether or not demand
responsiveness is a temporary problem, the Commission still should consider demand
responsiveness in its evaluation of the propriety of basing SRAC payments to QFs upon the PX
at any given time. If, as Mr. Kritikson states, the problem is temporary and is being addressed,
the PX can expect that concerns expressed in connection with demand responsiveness will soon
be addressed.

                           (iv)    The PX should have transparent pricing.
            The parties, including the PX, also agreed that PX pricing must be transparent. See, e.g.,


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Edison/Stern, Ex. 50, at 15:12 (“A transparent market price should be published for each day.”);
PG&E/Pappas, Ex.52, at 3 (“Markets prices must be transparent.”); SDG&E/Schelhorse, Ex. 51,
at 3:3 (“A transparent market price should be published for each day.”); PX/Kritikson, Ex. 153,
at 5 (“Price and market transparency is absolutely essential in order to achieve an efficient
competitive market.”); IEP/Branchcomb, Ex. 4, at 3 (referring to the standard for perfect
competition as “[b]uyers and sellers possess perfect information about prevailing prices and
current bids . . . .”). This uncontested standard should be adopted by the Commission.

                          (v)     There should be adequate market oversight and monitoring.
            There was also no dispute that there should be adequate oversight of the market and
monitoring of market performance. See, e.g., Edison/Stern, Ex. 50, at 15:17-18 (“The market
should have adequate monitoring and regulation to ensure that the aforementioned conditions
persist.”); SDG&E/Schelhorse, Ex. 51, at 3:8-9 (“The market should have adequate monitoring
and regulation to ensure that the above conditions exist.”); PX/Kritikson, Ex. 153, at 3 (listing as
one of the criteria, “[e]ffective monitoring and compliance.”) APX/Cazalet, Ex. 152 at 4:25-26
(“APX supports market monitoring.”). This uncontested standard should be adopted by the
Commission.

                   3.     The Commission should adopt the following five specific criteria for
                          determining whether the PX is functioning properly.
            While the CCC believes that the above-described standards should be adopted by the
Commission as over-arching criteria for determining whether the PX is functioning properly (as
the failure of the PX to satisfy any of the foregoing conditions should lead to conclusions that the
PX is not functioning properly for the purposes of the Section 390(c) inquiry), a number of these
standards articulate general concerns that may not be readily applicable in actual practice. Unless
the Commission adopts, in this phase of the proceeding, more specific criteria against which PX
performance can be measured, much of the work of Phase 2 will be on determining how one
actually measures whether the PX meets the general standards articulated above. More than
simply stating that there must not be too much market power being exercised, for example, the
Commission needs an actual measure to determine whether or not there is an excessive exercise
of market power. See, e.g., APX/Cazalet, Ex. 152, at 4:18-20. These measures are nothing less


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than criteria for determining whether the PX is functioning properly, which the Commission
should adopt in this phase of the proceeding.

            Having considered the primary concerns that have been identified with PX performance
to date (i.e., excessive market power, insufficient demand responsiveness, excessive amounts of
must-take resources and utility underscheduling), the CCC has proposed five specific criteria for
determining whether or not the PX is functioning properly. In order for some of these criteria to
be satisfied, improvements to the market will be required. To satisfy the other criteria, simply no
backsliding from current performance will be required. All of these criteria relate to the general
standards of market power, liquidity and demand responsiveness, the most elusive of the
concepts referred to above.4 While the CCC‟s proposed criteria admittedly did not enjoy the
same consensus as did the more general concepts, the record bears out the reasonableness of
these proposals. Each proposed criterion is discussed below.

                          (i)     For buyer or seller HHIs above 1,800, the Commission should
                                  require substantial evidence that such concentration does not
                                  impair the proper functioning of the PX market.
            The first criterion proposed by CCC will assist the Commission in determining whether
there is undue market power in the PX. As Mr. Beach has testified, market concentration indices
such as the Herfindahl-Hirschman index (“HHI”) are commonly used measures of the ability of
parties to employ excessive market power. CCC/Beach, Ex. 3, at 9:10-11. Obviously, if one
firm or a small group of firms possesses an overwhelming market share, the potential for the
exercise of market power is heightened.

            While noting that market concentration data alone may not be adequate to detect whether
undue market power is in fact being exercised (id. at 10:9-10), Mr. Beach proposes that the
Commission employ the United States Department of Justice standard HHI threshold for concern
of 1,800 as a market power screen. If neither sellers nor buyers have an HHI in excess of 1,800,
________________________

4
       The CCC believes that the transparency and market monitoring standards are adequately
       clear in and of themselves for application in Phase 2.




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then the Commission should not be concerned about market dominance as a means to exercise
undue market power. If either sellers or buyers have an HHI of 1,800 or more, then a more
detailed inquiry into market power issues is necessary and, as proposed by Mr. Beach, “the
Commission should require substantial evidence that such concentration will not impair the
functioning of the PX market.” Id. at 11:1-4.

            Edison witness Stern criticized this proposed criterion in rebuttal testimony.
Edison/Stern, Ex. 53, at 6:1-11. Dr. Stern‟s criticisms of this proposed criterion are unfounded
and should be rejected.

            First, Dr. Stern argues that the FERC already has granted the utilities market based rate
authority, implying that FERC has already concluded dispositively that the utilities are unable to
exercise undue market power. Id. at 6:1-11. This implication simply is not the case. As Mr.
Beach testified, “FERC‟s broad standards for market-based rates may not have prevented market
problems in the California Market.” CCC/Beach, Ex. 3, at 10:15-16. See also CCC/Beach, Tr.
at 599:2-8 (“FERC granted market-based rate authority, and, unfortunately, that grant has not
prevented some of the problems that have been encountered in the California market since it
started. For example, the FERC gave market-based rate authority and we still have problems in
the ancillary service markets that require the redesign of those markets.”). In fact, Dr. Stern
himself testified at length about the ability of sellers to exert undue market power in the PX
(SCE/Stern, Ex. 50, at 19:13-20:6). Many of the sellers to whom Dr. Stern likely is referring also
received market based rate authority from FERC, but nevertheless have been able to exert undue
market power in the PX such that Dr. Stern believes the PX is not functioning properly today.
See, e.g., 82 FERC 61,295 (granting market-based rate authority to Long Beach Generation
LLC); 82 FERC 61,126 (granting market-based rate authority to El Segundo Power, LLC);
83 FERC 61,317 (granting market-based rate authority to various Duke Energy entities).
Moreover, the excerpt from the FERC decision cited by Dr. Stern reveals that FERC did not
conclude dispositively that utility market power has ceased to be a concern; rather, FERC relied,
in large part, on the commitments of the utilities themselves not to seek to drive down prices and
on the presence of market monitoring institutions to permit the utilities to trade in the PX. In
other words, FERC determined that it would permit the utilities to proceed in the PX,


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notwithstanding its concerns about their incentives and market power, in light of FERC‟s ability
to later address the problems should they be detected. Finally, the Commission has an
independent obligation to consider the potential for anti-competitive results from its decisions; it
cannot simply rely on FERC‟s decision in this case. Northern California Power Agency v.
California Public Utilities Commission, 5 Cal. 3d 370, 379 (“As we have seen, it is clear that the
Commission must take into account the antitrust aspects of applications before it.”).

            Second, Dr. Stern argues that the ISO‟s Market Surveillance Committee (“MSC”) and
PX‟s Market Monitoring Committee (“MMC”) have concluded that, in light of the inelasticity of
the utilities‟ demand, the utilities are unable to exercise buyer market power. Edison/Stern, Ex.
53, at 6:12-7:7. Dr. Stern‟s argument is completely undercut, however, by his own admission
that the utilities have the ability to influence PX prices by shifting demand from the PX to the
ISO markets. Edison/Stern, Ex. 50, at 26, footnote 26 (“The demand elasticity observed in the
day-ahead market reflects the ability of wholesale demand to be allocated between the day-ahead
and real-time markets to arbitrage price differences between them.”). See also, Edison/Stern, Tr.
at 424:16-426:24. In fact, the utilities‟ ability to engage in “underscheduling” to drive down PX
prices is exactly the phenomenon observed and discussed at length by CCC witness Beach in his
prepared testimony, and by the MSC and MMC in the excerpts from the reports attached to Mr.
Beach‟s testimony. See, e.g., CCC/Beach, Ex. 3, at 13:15-14:13; October 18, 1999 MSC Report,
at 58 (Attachment RTB-4 of Ex. 3). Given the abundant evidence of the ability of the utilities to
influence PX prices, the Commission cannot simply rely on the presence of the MSC and MMC
(or on the FERC‟s grant of market based rate authority for that matter) to dispense entirely with
seller market power as a potential concern affecting the proper functioning of the PX.

            Finally, Dr. Stern criticizes the “substantial evidence” prong of the criterion as
unworkable. SCE/Stern, Ex. 53, at 7:8-19. The CCC admits to the absence of a precise formula
for what constitutes “substantial evidence” that excessive market concentration will not impair
the PX; this is something that the Commission will have to determine as part of its Phase 2
inquiry. Nevertheless, the “substantial evidence” threshold is far from unworkable. Judges,
juries, the Commission and other triers of fact employ standards such as this every day.
Reducing the inquiry to one of judging whether or not there is “substantial evidence” of market


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distortions will greatly simplify Phase 2.

                          (ii)    The ISO should have significantly raised or eliminated the current
                                  price caps in the real-time market (possibly retaining “safety net”
                                  or “damage control” price-cap authority).
            The CCC‟s second proposed criterion, removal or significant raising of the ISO‟s price
caps, also relates in large part to market power concerns. As CCC witness Beach testified: “In a
workably competitive market, competition should be adequate to discipline prices in the vast
majority of hours . . . there should be no need for price caps, or if a „damage control‟ cap is
retained, that cap should be reached only in exceptional circumstances – no more than a few
hours per year. ” CCC/Beach, Ex. 3, at 11:6-12. It is self-evident that if an artificial mechanism
like price caps are needed, and are actually utilized on more than isolated occurrences, there is
inadequate competition in the market and the first over-arching criterion, which had the near
unanimous support of the parties, has not been met.

            What is more, as Mr. Beach stated in direct testimony, and as Edison witness Stern
admitted on cross-examination, the price caps in the ISO‟s real-time market, combined with the
utilities‟ ability to shift load from the PX to the ISO market through “underscheduling” of
demand in the PX, have served to cap the PX day-ahead clearing price. CCC/Beach, Ex. 3 at
11:17-20; Edison/Stern, Tr. 426:15-19 (“Q. Does this arbitrage ability effectively cap the PX –
or has – historically, has this arbitrage ability effectively capped the day-ahead price at the ISO
real-time price caps? A. Yes, it has.”). As a result of the utilities‟ ability to shift demand from
the PX to the ISO real-time market, where prices for energy are capped, PX prices are not
reflecting the true value of energy in the market. Under such circumstances, it cannot be said that
the PX is functioning properly for the purposes of SRAC payments to QFs.

            Edison witness Stern, criticizing the CCC‟s proposed criterion, accuses the CCC of
attempting either to avoid exposure to the market by establishing a criterion that will not be
satisfied in the near term or to capture excessive prices in an uncapped market. Edison/Stern,
Ex. 53, at 8:3-16. In both cases Dr. Stern is wrong. In the first place, the PX and ISO are
undertaking various reforms in an attempt to improve market performance and avoid the need for
price caps. The ISO is expecting to revisit this need by the end of the summer. CCC/Beach,


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Ex. 3, at 12:10-11. It is very possible that the removal or substantial raising of the price caps
may occur by then. In the second place, Dr. Stern fails to recognize that the ISO‟s lifting the
price caps with FERC approval will be tantamount to a declaration that potentially high prices at
times are not “excessive.” The CCC is not seeking “excessive” prices; rather it is proposing that
the ISO‟s declaration of confidence in market performance through the removal or substantial
raising of the price caps will be a strong indication that the PX is functioning properly and its
prices are a sound basis for SRAC payments to QFs.

                          (iii)   The day-ahead PX and real-time ISO market prices should have
                                  averaged within 20% of each other during peak demand hours.
            As Mr. Beach has testified, if the PX were workably competitive, its market prices would
converge for similar products in the PX and in other markets (i.e., for energy in the day-ahead
and day-of markets and in the ISO‟s real-time markets). CCC/Beach, Ex. 3, at 13:11-14. As Mr.
Beach explains, this is because differences in prices in the relevant markets will disappear “as
market participants quickly arbitrage away any price difference between the markets.”
CCC/Beach, Ex. 3, at 13:13-14. For example, if prices in the ISO real-time market were
expected to exceed prices in the PX day-ahead market due to a sudden major facility outage,
sellers should be expected to attempt to shift their supply from the PX market to the ISO market,
causing the ISO price to decline and the PX price to increase until they reach equilibrium. See,
e.g., SDG&E/Schelhorse, Tr. at279:5-280:12. If market prices in the relevant markets do not
converge, it is likely that there is a defect in the market that is permitting participants to constrain
prices from flowing to competitive levels.

            For this reason, the CCC proposes that the Commission, in evaluating whether the PX is
functioning properly, consider the degree of convergence between the PX day-ahead and the ISO
real-time markets. Obviously, the prices in these two markets cannot be expected to be
equivalent in each hour. In fact, perfect convergence may never occur, as market participants
may consider the risks of participating in one market versus the other to be different, and
unexpected events could cause one market price to deviate from the other from time to time. As
experience has shown, however, the PX and ISO market prices generally have converged
extremely well in all but the hours of peak demand (i.e., ISO demand in excess of 36,000 MW).



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See CCC/Beach, Ex. 3, at 13:15-14-13; Id. at Figures 1 and 2. During these periods, there is a
dramatic and sustained lack of convergence, which CCC witness Beach, the ISO‟s MSC and the
PX‟s MMC attribute, at least in part, to the utilities‟ practice of underscheduling demand in the
PX markets so as to take advantage of the price caps in the ISO real-time market and keep prices
in the PX artificially low. Id. As a result, the CCC proposes that the Commission adopt as a
functioning properly criterion that the PX day-ahead price and the ISO real time price during the
hours when demand exceeds 36,000 MW should average within 20 percent of each other.

            Both Edison witness Stern and SDG&E witness Schelhorse submitted testimony in
opposition to the CCC‟s proposed price convergence criterion. Dr. Stern primarily argues that
prices in the PX and ISO markets are not necessarily going to be equivalent because of
differences in bidder expectations and perceptions of risk. Edison/Stern, Ex. 53, at 9:16-11:10.
As discussed above, however, the CCC is not proposing that the Commission require perfect
convergence; rather, the CCC is proposing that the average prices during certain hours (those
hours in which market power is most likely to influence prices) remain within 20% of each other.
Both Dr. Stern and Dr. Schelhorse admit that the PX and ISO market prices should equilibrate.
Id. at 9:24-10:2. SDG&E/Schelhorse, Tr. at 280:10-11. In fact, in most hours this equilibrium
has been so perfect that Dr. Schelhorse states that the “prices have, in fact, converged.”
SDG&E/Schelhorse, Ex. 54, at 8:15-16. Neither Dr. Stern nor Dr. Schelhorse can account for
the extreme and sustained lack of equilibrium during peak demand periods, other than as a
function of the exercise of market power. In fact, Dr. Stern testified at length about how market
power has affected PX prices during peak demand periods and how, as a result, the PX is not
functioning properly. Edison/Stern, Ex. 50, at 20:13-21:6. As such, requiring average
convergence within 20% is an entirely reasonable approach to the issue.

            Dr. Stern and Dr. Schelhorse also argue that CCC witness Beach casts unjustified
aspersions on the utilities by accusing them of “underscheduling.” Edison/Stern, Ex. 53,
at 10:9 16; SDG&E/Schelhorse, Ex. 54, at 9:26-11:19. They argue that the lack of convergence
is more appropriately tied to the exercise of market power by sellers, not buyers. Id. In the first
place, there is clear evidence, in the reports of the ISO‟s MSC and the PX‟s MMC that the
utilities underscheduling behavior contributes to the lack of convergence between the day-ahead


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and ISO real time prices at high levels of demand. As the ISO‟s MSC stated:

            When load exceeded 40,000 MW, over 6% of the actual system load went
            unscheduled. This explains why the real-time price is significantly higher than the
            PX price during periods of high loads. This pattern of load under-scheduling
            during periods of high loads is mainly the result of IOUs hedging the risk of being
            exposed to a high price in the PX market.

CCC/Beach, Ex. 3, Attachment RTB-4 (ISO MSC Report, October 18, 1999), at 58. See also,
Id., Attachment RTB 3 (PX MMC Report, March 9, 1999), at 47. More importantly, though, it
does not really matter if the cause of the lack of convergence is the use of market power by
buyers or by sellers. If during a substantial number of hours, the PX price is significantly lower
than the true value of energy in the market, i.e., if there is an inadequate convergence between the
ISO and PX prices during these hours, the Commission should not determine that the PX is
functioning properly.

            Alternatively, the Commission may address the CCC‟s primary convergence criterion
concern, the ability of the utilities to deflate artificially the PX price through underscheduling of
demand in the PX, by setting SRAC equal to the ISO real-time price during periods when
demand is underscheduled by more than five percent. As explained by CCC witness Beach,
when the utilities are engaged in significant underscheduling of demand, “[t]he ISO real-time
price represents the true price at which the market clears.” CCC/Beach, Ex. 3, at 16:1-2. In
other words, when the utilities are buying power out of the ISO real-time market, by shifting
demand there through underscheduling, it is the real-time market price, not the PX price , that
reflects the utilities‟ avoided cost.

            This proposed pricing alternative, although it admittedly employs a price indicator other
than the PX market clearing price, nevertheless complies with Section 390(c), as it only would
apply in limited instances and the SRAC methodology as a whole would remain “based on” the
PX price. In addition, the five percent threshold should account for ordinary differences between
schedules and actual demand, and only apply to relatively significant excursions. Finally, it is
important to recognize that, although the CCC‟s primary concern is one of potential buyer market
power, even if underscheduling were to occur through honest forecast error, the CCC‟s proposed
alternative still merits adoption. Irrespective of the cause, if the utilities‟ marginal demand is

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being served in the ISO real-time market as opposed to the PX, the ISO real-time price represents
the utilities‟ avoided cost. As a result, CCC/Watson‟s alternative SRAC pricing proposal, which
would apply only in limited circumstances, could be adopted in lieu of the CCC‟s proposed
convergence criterion.

                          (iv)    The PX day-ahead market clearing price should be zero in no more
                                  than one percent of the hours in the immediately preceding twelve
                                  month period.
            As CCC witness Beach and IEP witness Branchcomb testified, and as the PX itself has
confirmed, the presence of large amounts of must take resources that are bid into the PX at a zero
bid price, distorts prices produced by the PX and, as a result, the proper functioning of the PX.
See, e.g., CCC/Beach, Ex. 3, at 16-20-21; IEP/Branchcomb, Tr. at 521:25-522:17; CCC/Beach,
Ex. 3. Attachment RTB-5 (PX Annual Report to FERC, July 30, 1999), at 34. The CCC
recognizes that there are legitimate reasons supporting the bidding of these units into the PX at
zero, and is not in any way critical of the practice per se. The problem, however, is that the
practice has an undeniable impact upon the PX clearing price; the more must take resources
bidding in, the worse the results from a market performance standpoint. As a result, the CCC
proposes that, in order for the Commission to find the PX to be functioning properly, the PX
price should equal zero no more than one percent of the hours in the twelve month period
immediately preceding the Commission‟s inquiry.

            Again, Edison witness Stern and SDG&E witness Schelhorse are the critics with respect
to the CCC‟s proposed criterion. Dr. Schelhorse complains that the one percent threshold is
“arbitrary and meaningless” (SDG&E/Schelhorse, Ex. 54, at 9:2), while Dr. Stern argues the
criterion is not needed as the PX price historically has been zero in fewer than one percent of the
hours. Edison/Stern, Ex. 53, at 11:13-22. Dr. Stern also asserts that there is no evidence that the
PX price is being materially deflated by zero bids, when PX prices are compared to prices in the
PJM market. Edison/Stern, Ex. 53, at 11:20-22.

            As Mr. Beach explained on cross-examination, the one percent threshold is far from
arbitrary and meaningless. First, one percent of the hours reflects a “relatively small number” so
that, if the less than one percent standard were met, the Commission could be confident that must


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take resources were not having a significant effect on overall PX prices. CCC/Beach,
Tr. 619:5-11. Second, one percent reflects roughly the percentage of zero-priced hours observed
in the PX in the first 21 months of operation (including months in which there was a lot of zero-
priced hydro power), and this criterion would ensure that there is no significant backsliding
before the Commission makes its decision in Phase 2. Id. at 619:12-23. This is particularly
important, as the ISO recently proposed, and received approval of, the opportunity to dispatch
Reliability Must Run (“RMR”) generation prior to the determination of the PX day-ahead
schedule, a factor that could lead to significantly more zero-priced hours. CCC/Beach, Ex. 3, at
16:22-18:2; 90 FERC 61,345.

            While Dr. Stern is correct that, looking at the most recent twelve months, this criterion
would be met, that is besides the point. As explained above, this criterion is to ensure that
between today and the date of the Commission‟s functioning properly determination, PX
performance does not significantly deteriorate. Finally, Dr. Stern‟s attempt to compare prices in
the PX to prices in PJM, which serves the mid-Atlantic states, simply is not persuasive. Bidding
substantial amounts of resources that have marginal costs in excess of zero into the PX at zero, is
going to alter artificially the supply curve and affect PX clearing prices. See, e.g., CCC/Beach,
Ex. 3, Attachment RTB-5 (PX Annual Report, July 30, 1999) at 34.

                           (v)     The rate freeze must have ended.
            As discussed above, there is little dispute that the absence of adequate demand
responsiveness in the PX distorts the PX price. CCC/Beach, Ex. 3, at 19:15-21:8. Edison/Stern,
Ex. 50, at 17:6-18:6. ORA/Linsey, Ex. 100, at 12:8-14. Every witness commenting upon the
inadequacy of demand responsiveness has attributed it, at least in substantial part, to the presence
of the current transition-period retail rate freeze. CCC/Beach, Ex. 3, at 20:6-8. Edison/Stern,
Ex. 50, at 16:15-16. ORA/Linsey, Ex. 100, at 12:9-10. Even PX witness Kritikson, who does
not believe that demand responsiveness should be a criterion at all, attributes the lack of demand
responsiveness to the utilities‟ rate freezes, which he describes as a temporary phenomenon.
PX/Kritikson, Ex.153, at 8-9. The obvious result of this widespread concern is the final criterion
proposed by the CCC; the Commission should find that the PX is not functioning properly until
the rate freeze of each utility has terminated.


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            Only Edison witness Stern opposed the CCC‟s proposed criterion. Acknowledging that
demand responsiveness is indeed a legitimate functioning properly concern, Dr. Stern asserts that
the Commission should address the concern through an adjustment to the SRAC pricing
mechanism. Edison/Stern, Ex. 53, at 12:10-21. Thus, Dr. Stern does not dispute the merits of
the proposed criterion, rather he proposes an alternative means of addressing the underlying
concern. The SRAC pricing mechanism proposed by Edison, however, in no way accounts for a
lack of demand responsiveness in the PX; rather, it is nothing more than an attempt to reduce QF
payments. The proper manner for the Commission to address the lack of demand responsiveness
in the PX is to wait until there is more demand responsiveness in the PX before finding the PX to
be functioning properly.

            B.     SRAC Energy Pricing.
                   1.     Introduction and Summary
            There is no dispute as to the applicable legal standards that govern the Commission‟s
determination of the SRAC energy payment methodology to be adopted in this proceeding. Such
SRAC energy payment methodology must comply both with the requirements of PURPA, as
implemented by FERC, and with the provisions of Public Utilities Code Sections 390(c)
and 390(d).

            FERC‟s long-standing regulations under PURPA require that payments made to QFs
reflect the full avoided costs of the utility purchasing the QF power. 18 CFR 292.304(b)(2);
American Paper Institute, Inc. v. American Electric Power Service Corp., 461 U.S. 401 (1982)
(upholding FERC‟s “full avoided cost rule”). See also, Edison/Jurewitz, Tr. 210:2-6 (testifying
that a QF payment methodology that systematically results in payments below avoided cost
would violate FERC‟s rules implementing PURPA). “Avoided costs” are defined by FERC as
“the incremental costs to an electric utility of electric energy or capacity or both which, but for
the purchase from the qualifying facility or qualifying facilities, such utility would generate itself
or purchase from another source.” 18 CFR 292.101.




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            Section 390(c) requires, after the Commission makes the functioning properly
determination discussed above, and after one of two other conditions are satisfied,5 that SRAC
energy payments “shall be based on the clearing price paid by the independent Power Exchange.”
Section 390(d) requires that the value of capacity in the PX price, if any, not be paid to QFs with
contractually specified firm capacity payments, forecast as-available capacity payments and
forecast as-delivered capacity payments. Section 390(d) further provides that “[t]he value of
capacity in the clearing price, if any, equals the difference between the market clearing customer
demand bid at the level of generation dispatched by the independent Power Exchange and the
highest supplier bid dispatched.”

            Essentially, there have been three types of SRAC proposals advanced in this proceeding.6
First, both CAC and IEP propose to establish SRAC energy payments using a methodology that
adjusts the day-ahead PX clearing price to reflect what such price would have been if a specified
group of QFs were removed from the resource mix. CAC/Ross Ex. 2, at 6:11-18;
IEP/Branchcomb, Ex. 4, at 9-11. CAC and IEP propose further that the language of Section
390(d) with respect to the determination of the value of capacity in the clearing price, if any, be
taken literally and illustrate, by reference to a graph that is shown in Exhibit 9, how such value is
to be determined. The CAC and IEP proposals clearly reflect the costs that the utilities would
incur “but for” the presence of QFs in the resource mix. They also comport with the
Commission‟s historical “QFs-In/QFs-Out” method of determining avoided cost. They are based
upon the PX price, as required by Section 390(c), and comply with Section 390(d). As reflected
in the comparative pricing exhibits sponsored by CAC and IEP, each of their proposed
methodologies would result in payments to QFs that exceed the PX day-ahead clearing price.

________________________

5
       The other two conditions involve a specified level of divestiture of utility fossil generating
       facilities and the utilities‟ recovery of “going forward costs” from transactions with the PX
       or ISO.
6
       CCC/Watson acknowledge that FPL Energy, LLC and the Tri-Dam Power Authority have
       proposed an alternative SRAC proposal for intermittent resource QFs. CCC/Watson take no
       position on this proposal.




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CAC/Ross, Ex. 15; IEP/Branchcomb, Ex. 18.

            Second, far at the other end of the spectrum of pricing proposals advanced in this
proceeding lie Edison‟s and ORA‟s SRAC proposals. Edison and ORA both propose to base
SRAC energy payments upon the energy-related costs of a hypothetical new market entrant.
Edison/Jurewitz-Davis, Ex. 50, at 36:6-50:9. ORA/Sabino, Ex. 100, at 43:18-48:13. ORA offers
a secondary proposal to determine SRAC energy payments using the PX price capped at the
energy-related costs of the least efficient units in the market. Id. at 41:19-43:17. As discussed in
detail below, the Edison/ORA new entrant proposal should be rejected because (i) it violates
Section 390(c) by proposing to base SRAC upon the costs of a hypothetical new entrant rather
than upon the PX market clearing price; (ii) it violates Section 390(d) by proposing to subtract
from the PX market clearing price a value of capacity that exceeds the value specified in Section
390(d); (iii) it violates PURPA by failing to base SRAC upon the short-run costs that the utilities
will actually avoid as a result of purchases from QFs; and (iv) implementing it, if adopted, will
be extremely controversial and administratively burdensome. ORA‟s price cap proposal also
should be rejected as it suffers from all of the same defects as the new entrant proposal (with the
exception that the price cap proposal arguably complies with Section 390(c) as being based upon
the PX market clearing price). Based upon the comparative exhibits prepared by Edison and
ORA, the new entrant proposal would result in QF payments significantly below the PX day-
ahead clearing price for the zone in which the QFs were located. Edison/Davis, Ex. 67;
ORA/Sabino, Ex. 103.7

            A third SRAC energy pricing proposal was advanced by CCC/Watson, SDG&E and
PG&E. These parties propose simply to set SRAC energy payments equal to the PX day-ahead
clearing price for the zone in which the QFs are located, less the value of capacity, if any, in the
________________________

7
       While ORA witness Sabino compared the new entrant proposal and the heat rate cap
       proposal to the unconstrained PX market clearing price, Edison limited its comparison to the
       current SRAC transition formula. Nevertheless, the discounting effect of Edison‟s specific
       pricing example may be illustrated by comparing Edison‟s comparative exhibit to the PX
       price data reflected in the comparative exhibits of other parties.



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PX price as specified in Section 390(d). CCC/Watson/Beach, Ex. 3, at 23:1-21:15;
PG&E/Pappas, Ex. 52, at 1-2, 5-6; SDG&E/Schelhorse Ex. 51, at 6:5-8, SDG&E/Nelson Ex. 70,
at 4:20-21.8 It is extremely telling that the CCC and Watson, on one hand, and PG&E and
SDG&E, on the other hand, independently advanced the same SRAC proposal. As discussed in
detail below, the Commission should adopt the SRAC energy pricing proposal advanced by
CCC/Watson, PG&E and SDG&E because it (i) complies with PURPA by setting QF payments
equal to the utilities‟ short-run avoided costs; (ii) complies with Section 390(c) by basing SRAC
upon the PX day-ahead market clearing price; (iii) complies with Section 390(d) by
implementing its express terms and intended meaning; (iv) is easy to implement and transparent;
(v) is not subject to manipulation by any party (assuming that the PX is functioning properly);
and (vi) provides accurate and prospective price signals.

                   2.      The Commission should set SRAC energy payments equal to the day-
                           ahead PX price for the zone in which the QF is located, less the value
                           of capacity in the PX price, if any, as determined in accordance with
                           Section 390(d).
            The best solution to any particular problem is usually the simplest solution. It is just so in
this proceeding.

            As discussed above, parties with diametrically opposed perspectives, CCC/Watson,
SDG&E and PG&E each have proposed to set SRAC energy payments equal to the PX day-
ahead clearing price for the zone in which the QF is located, less the value of capacity, if any,
determined in accordance with the express language of Section 390(d). As discussed below, in
light of the applicable legal standards, the nature of the energy market in California, the
________________________

8
       CCC/Watson note that SDG&E has sponsored an alternative proposal based upon a
       weighted average of PX day-ahead, PX day-of and ISO real-time market prices.
       SDG&E/Schelhorse Ex. 51, at 6:10-7:17. SDG&E witness Nelson makes clear in his
       testimony supporting the comparative pricing exhibit that SDG&E‟s primary proposal is the
       zonal PX day-ahead clearing price. SDG&E/Nelson Ex. 70, at 4:20-21. In addition, SDG&E
       does not expressly discuss the capacity subtractor from the PX day-ahead clearing price;
       CCC/Watson have assumed from its failure to propose otherwise that SDG&E would simply
       apply Section 390(d) literally.



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Commission‟s objectives for SRAC pricing and the controversy engendered by the other SRAC
proposals in this proceeding, the CCC/Watson, SDG&E and PG&E proposal is simply the
“right” answer; it should be adopted by the Commission.

                           (i)     The CCC/Watson, SDG&E and PG&E SRAC pricing proposal
                                   complies with PURPA.
            The utilities are currently required to buy all of their electric energy from the PX.
D.95-12-063, as modified by D.96-01-009, at 51. While the utilities may employ more than one
PX market (the utilities are currently authorized to trade in the PX day-ahead, day-of and block-
forward markets), and, as discussed above, the utilities actually trade in the ISO‟s real-time
market during high demand hours,9 more than ninety percent of their energy purchases have been
and continue to be made from the PX day-ahead market. CCC/Beach, Ex. 3, at 23:4-5 (“Over the
initial year of the new market, the IOU‟s appear to have bought most (at least 90%) of the power
in the PX day ahead market.”); SDG&E Schelhorse, Ex. 51, at 7:6-7 (“Since the start of the
market, SDG&E has purchased over 90% of its total load requirement from the Day-Ahead
market.”); PG&E/Pappas, Ex. 52, at 5 (“[T]he investor-owned utilities (IOUs) currently purchase
approximately 95% of their energy demand through the PX day-ahead market . . . .”).

            The combination of the current “buy PX” mandate and the utilities‟ overwhelming
reliance on the PX day-ahead market for their energy purchases leads to the simple and obvious
conclusion that, but for purchases from QFs, the utilities would buy additional power at the PX
day-ahead market clearing price, indeed, through the PX day-ahead market.10 CCC/Beach, Ex. 3,

________________________

9
       In fact, PG&E witness Pappas expressly states that the “IOUs also purchase energy through
       the ISO‟s imbalance market . . . .” PG&E/Pappas, Ex. 52, at 5, footnote 2.
10
       A necessary caveat to this statement, as recognized expressly by CCC witness Beach and
       PG&E witness Pappas, and implicitly by SDG&E witness Schelhorse, is that, in order for
       the PX day-ahead price to reflect the utilities‟ avoided cost, the PX must be functioning
       properly. CCC/Beach, Ex. 3, at 24:1-19 (discussing an alternative SRAC pricing proposal to
       account for underscheduling by the utilities, which distorts the PX clearing price and makes
       the ISO real-time price better reflective of avoided costs during the relevant time periods);
       SDG&E Schelhorse, Ex. 51, at 7:7-17 (acknowledging that the ISO real-time price affects
                                                                                           (continued…)

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at 23:6-7; SDG&E Schelhorse, Ex. 51, at 6:5-6; PG&E/Pappas, Ex. 52, at 5. Even after the
current buy mandate ends and the utilities are authorized to trade more freely, the PX day-ahead
market clearing price should remain, at least for the foreseeable future, a fair indicator of the
utilities‟ short-run avoided costs. So long as the market is functioning properly, the prices for
energy available in the market on a short-run basis (whether in the PX, ISO or other organized
exchanges, or in bilateral contracts) should be expected to converge. See, e.g., CCC/Beach, Ex.
3, at 13:11-14. Thus, so long as the PX day-ahead market continues to possess sufficient
liquidity, and so long as participants are unable to exercise undue market power in order to
preserve arbitrage opportunities, the PX day-ahead market will continue to reflect the utilities‟
short-run avoided cost.

            As the California Legislature recognized in its enactment of Section 390(d), it is possible
in the restructured energy market that the PX clearing price will reflect a value of capacity in
addition to a value of energy. As QFs in California are, by contract, compensated separately for
SRAC energy and for providing capacity, including firm and as-available capacity (see, e.g.,
Edison/Bergmann Tr. at 347:2-11), SRAC energy payments should not include the value, if any,
of capacity in the PX clearing price. Therefore, in order to ensure that QF energy payments do
not exceed the short-run energy cost that the utility avoids, CCC/Watson, PG&E and SDG&E
propose to remove from QF SRAC energy payments the value of capacity, if any, present in the
PX day-ahead clearing price. As discussed below, the proposed method for doing so is in
compliance with the formula prescribed in Section 390(d).

            In sum, assuming that the PX is functioning properly, the PX day-ahead market clearing
price reflects the costs that the utilities avoid by purchasing power from QFs. Removing the
value of capacity, if any, in the clearing price yields an avoided cost of energy. As a result,
setting SRAC energy payments to QFs equal to the PX day-ahead clearing price, less the value of

________________________
(…continued)
       the price of replacement power that would be procured by SDG&E); PG&E/Pappas, Ex. 52,
       at 5 (“[t]his market [the PX day-ahead market], if functioning properly, provides a
       reasonable approximation of the IOUs‟ avoided cost of energy”).




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capacity, if any, determined in accordance with the express language of Section 390(d), complies
with PURPA.

                           (ii)    The CCC/Watson, SDG&E and PG&E SRAC pricing proposal
                                   complies with Section 390(c).
            Section 390(c) requires that SRAC energy payments be based upon the PX clearing price.
The CCC/Watson, SDG&E and PG&E SRAC pricing proposal clearly complies with Section
390(c), as it would set SRAC equal to the PX day-ahead clearing price, less the value of capacity
in the clearing price. Even Edison witness Stern states that “it cannot be disputed that such a
pricing methodology would comply with the requirement in Section 390(c) that SRAC be „based
on‟ the PX clearing price.” Edison/Stern, Ex. 53, at 27:6-8.

                           (iii)   The CCC/Watson, SDG&E and PG&E SRAC pricing proposal
                                   complies with Section 390(d).
            Section 390(d) requires that the value of capacity in the PX price, if any, not be paid to
QFs with contractually specified firm capacity payments, forecast as-available capacity payments
and forecast as-delivered capacity payments. Section 390(d) further provides that “[t]he value of
capacity in the clearing price, if any, equals the difference between the market clearing customer
demand bid at the level of generation dispatched by the independent Power Exchange and the
highest supplier bid dispatched.” The CCC/Watson, SDG&E and PG&E SRAC pricing proposal
complies with Section 390(d) by subtracting the value of capacity as described in Section 390(d)
from SRAC energy payments.

            Both ORA and Edison have criticized the method for determining the value of capacity in
the clearing price as set forth in Section 390(d). See, e.g., Edison/Stern, Ex. 50, at 25-12-14;
ORA/Linsey, Ex. 100, at 34:14:23. They argue that there is more capacity value in the clearing
price than is reflected in the formula for determining such value in Section 390(d), and that
applying Section 390(d) would result in excessive SRAC energy payments in violation of
PURPA. ORA/Linsey, Ex. 100, at 1-23 (explaining how “ORA reaches the conclusion that the
Section 390(d) formula exceeds avoided cost for several reasons”); Edison/Bergmann, Ex. 50, at
5:10-14 (“SCE shows that application of the formula in Section 390(d) . . . is inconsistent with
the avoided cost principle of PURPA . . . .”). As a result, they argue that the Commission should


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ignore the second sentence of Section 390(d) in designing its SRAC methodology in this
proceeding. As Mr. Linsey stated on cross-examination, for example:

                   Q. So its your position that the Commission could choose not to apply the
                   second sentence of 390(d); correct?

                   A. Yes.

ORA/Linsey, Tr. 693:15-17. Edison‟s and ORA‟s position is simply illegal and must be rejected.

            The Commission must, in discharging its obligations in this proceeding, comply with
Section 390(d), even if it believes that such law conflicts with PURPA. The California
Constitution, Article III, section 3.5 specifically provides that, “[a]n administrative agency, . . .
has no power . . . [t]o declare a statute unenforceable, or to refuse to enforce a statute on the basis
that federal law or federal regulations prohibit the enforcement of such statute unless an appellate
court has made a determination that the enforcement of such statute is prohibited by federal law
or federal regulations.” Cal. Const. art III, § 3.5(c); Reese v. Kizer, 46 Cal. 3d 996, 998 (1988).
The purpose of this portion of the California Constitution is “to prevent agencies from using their
own interpretation of the Constitution or federal law to thwart the mandates of the Legislature.”
Reese, 46 Cal. 3d at 1002. No appellate court has ruled, or even reviewed, the potential
preemption of Section 390(d) by PURPA as asserted by Edison and ORA.11 Therefore, the
CPUC has no authority to refuse to implement Section 390(d).

            When the law is unambiguous, the Commission has no discretion and must simply apply
the law. As CCC witness Beach testified, “[t]he definition of capacity value provided in the last
sentence of Section 390(d) is clear and precise . . . .” CCC/Beach, Ex. 3, at 25:19-20. As such,
the Commission should implement the plain meaning of Section 390(d), which is embodied in
the SRAC proposal of CCC/Watson, SDG&E and PG&E.

________________________

11
       While the CPUC cannot rule on federal preemption issues, it is proper for the issue to be
       raised before the administrative agency to preserve the matter for appeal. Delta Dental Plan
       of Cal., Inc. v. Mendoza, 139 F.3d 1289, 1296 (9th Cir. 1998).




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            Even if there were any ambiguity in Section 390(d), it is clear by looking to the legislative
intent that Edison‟s and ORA‟s interpretation of Section 390(d) must be rejected in favor of the
interpretation given to the statute by CCC, Watson, IEP, CAC, SDG&E and PG&E in this
proceeding. As Mr. Beach testified, the definition of the value of capacity in Section 390(d) is
almost identical, on a word-for-word basis, to the definition of the value of capacity contained in
two agreements on PX-based SRAC pricing among CCC, IEP and Edison, and CCC, IEP, CAC
and PG&E. CCC/Beach, Ex. 3, at 26:10-12.12 See also PG&E/Pappas, Ex. 52, at 5. Attached to
both of these agreements is a graphical representation of how the value of capacity language in
both the settlements and the statute should be interpreted. This is the same graph that is reflected
in Exhibit 9, and upon which CCC, Watson, PG&E, SDG&E, CAC and IEP propose to
determine the value of capacity in this proceeding. In fact, as is common knowledge, AB 1890
was developed through negotiations among numerous stakeholders, including Edison, PG&E,
SDG&E, CCC, CAC and IEP. Section 390, including Section 390(c) and 390(d) were developed
as part of this process and were intended to reflect the prior agreement of the parties on the
relevant issues, including the value of capacity, if any, in the PX clearing price.

            There was considerable attention devoted in testimony and during the hearings as to
whether the earlier agreements concerning the value of capacity in the clearing price continue to
bind the parties and whether the various proposals of the parties comply with these agreements.
Edison, for example, has asserted that the value of capacity described in the earlier agreements
and then later in Section 390(d) is in some way not binding because certain underlying
assumptions did not come to pass (e.g., certain aspects of the original PX design were not
implemented and the rate freeze adopted in AB 1890 minimized demand responsiveness). See,
e.g., Edison/Stern/Balance/McCarthy, Ex. 50, at 26:17-33:10.

            This entire debate, however, is irrelevant to the Commission‟s implementation of the
statute. The Legislature intended that the value of capacity in the clearing price, which is to be

________________________

12
       These agreements are attached as Attachment RTB-6 and Attachment RTB-7 to Exhibit 3.




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subtracted from the clearing price to determine SRAC energy payments, be calculated in the
manner in which the plain meaning of Section 390(d) indicates. Even if all of the assumptions
underlying the parties‟ expectations were not ultimately implemented, the intent of the
Legislature is clear, and the Commission must apply the statute.13

            Finally, contrary to ORA‟s and Edison‟s assertions, the value of capacity described in
Section 390(d) is the academically appropriate manner in which to calculate the value of capacity
in the PX clearing price. As CCC witness Beach testified:

            As I have discussed, in a properly functioning market, suppliers will bid their
            marginal costs of production, in order to maximize their revenues. If the
            aggregate supply curve falls below the demand curve at all points, then the market
            will clear on a demand-side bid at the level of generation of the highest supply
            bid. The difference between the market-clearing demand bid and the highest
            supply bid dispatched represents the additional value to the buyer of ensuring that
            he is supplied with power. In other words, it represents the value to the buyer of
            the system‟s capacity to provide him with power. It is the capacity value in the
            PX price. If the supply and demand curves intersect, then the value of power to
            the buyer is the same as the marginal cost of producing another MWh of energy,
            and the capacity value in the market-clearing price is zero. More generally, both
            Edison and ORA commit a fundamental error in trying to equate the capacity
            value in the PX price with the fixed costs that a generator is recovering through its
            PX sales. This reflects an outdated view of the nature of capacity. In today‟s
            market, capacity is not a category of costs, it is a service-the ability to call on a
            generator to deliver energy when it is needed. As noted above, when the demand
            side is willing to pay more for electricity than the highest supply bid, then the
            difference between the demand and supply-side bids is capacity value, because if
            reflects the premium that the buyer is willing to pay to ensure that he receives
            electricity.

CCC/Beach, Ex. 7, at 19:12-20:2.



________________________

13
       It is worth noting that Edison‟s testimony about the failure of the underlying assumptions is
       not credible. First, Edison was aware, at the time the Legislature was codifying the value of
       capacity in Section 390(d), that the legislature also was adopting a rate freeze and Edison
       raised no objection at the time (Edison/Stern/Balance/McCarthy, Tr. 330:20-331-4).
       Second, the components of PX bidding that are currently in place, and the definition of
                                                                                          (continued…)

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            In fact, the formula included in Section 390(d) already has been embraced by the
Commission as the appropriate measure for determining the value of capacity in the PX clearing
price. As the Commission stated in Decision 96-10-036 in respect of the value of capacity in the
restructured energy market:

            Even during hours that the system is not in a state of minimum load, the
            difference between the market clearing customer demand bid at the level of
            generation dispatched by the independent power exchange and the highest
            supplier bid dispatched, is expected by some to be frequently, if not always, zero.
            This result occurs from the flexibility of decremental demand bids expressing
            interruptible customers willingness to be curtailed over a particular clearing price.
            A supplier bid that is higher than this clearing price will not clear the market, and
            the difference between the demand bid and the last clearing supplier bid could
            frequently if not always be zero.

D.96-10-036, at 35-36. As such, Edison‟s and ORA‟s arguments should be rejected.

            In sum, the CCC/Watson, SDG&E and PG&E SRAC pricing proposal clearly complies
with Section 390(d), which is binding upon the Commission and is an appropriate measure of the
value of capacity in the PX clearing price.

                           (iv)    The CCC/Watson, SDG&E and PG&E SRAC pricing proposal is
                                   easy to implement and transparent.
            Another significant benefit of the CCC/Watson, SDG&E and PG&E SRAC pricing
proposal is that it is extremely easy to implement and transparent, as the “zonal, day-ahead PX
price for the next day is readily available on the ISO website.” CCC/Beach, Ex. 3, 23:15-19.
Even Edison witness Stern agrees that this proposal “provides simplicity [and]
transparency . . . .” Edison/Stern, Ex. 53, at 27:8. In light of the historical controversies
associated with SRAC implementation and the drain on the parties‟ and the Commission‟s
resources that resulted, as discussed more fully below, this benefit should not be overlooked.


________________________
(…continued)
       capacity value in Section 390(d), both were contained in the underlying PX design criteria
       (Id., at 334:15-336:4).




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                          (v)     The CCC/Watson, SDG&E and PG&E SRAC pricing proposal is
                                  not subject to manipulation by any party (assuming that the PX is
                                  functioning properly).
            Still another benefit associated with the CCC/Watson, SDG&E and PG&E SRAC pricing
proposal is that, assuming the PX is functioning properly, the methodology is not subject to
manipulation. See, e.g., CCC/Beach, Ex. 3, at 23:20-25. Assuming that the PX is functioning
properly, the PX market clearing price will reflect the value of energy in an open and competitive
market. Neither QFs, the utilities nor consumers should be able to distort this market price (and,
therefore, QF payments) to their financial benefit.

                          (vi)    The CCC/Watson, SDG&E and PG&E SRAC pricing proposal
                                  provides accurate and prospective price signals.
            Finally, the CCC/Watson, SDG&E and PG&E SRAC pricing proposal provides accurate
and prospective price signals to QFs, as the day-ahead zonal PX price is published in advance
and reflects the costs of congestion. CCC/Beach, Ex. 3, at 23:26-28. See also Edison/Stern, Ex.
53, at 27:8-9. As CCC witness Beach testified, “[a]ccuracy of the price signals sent to QFs is a
major goal of the Commission‟s SRAC policy.” CCC/Beach, Ex. 17, at 11:16. As the
Commission itself has stated: “Moreover, we believe avoided cost pricing and the vitality of the
standard offer process require accurate price signals for both energy and capacity.” D.86-05-024,
1986 Cal. PUC Lexis 303 (May 7, 1986), at *20. In fact, the Commission subsequently referred
to its “obligation to provide the most accurate price signals to QFs based upon avoided
costs . . . .” D.87-12-066, 1987 Cal. PUC Lexis 416 (Dec. 22, 1987), at *10. Clearly, the
accuracy of the price signals sent by the CCC/Watson, SDG&E and PG&E SRAC pricing
proposal supports its adoption by the Commission.

            For this, and for all of the foregoing reasons, the Commission should set SRAC energy
payments equal to the day-ahead PX price for the zone in which the QF is located, less the value
of capacity in the PX price as determined in accordance with Section 390(d), as proposed by
CCC/Watson, SDG&E and PG&E.

                   3.     The Commission should reject the Edison/ORA new entrant proposal.
            Unlike the SRAC pricing proposal made by CCC/Watson, SDG&E and PG&E, the



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Edison and ORA new entrant proposal ignores the requirements of PURPA and Section 390 and
is little more than a blatant attempt to reduce payments to QFs. Furthermore, the proposal would
be an administrative nightmare, returning the parties and the Commission to the days of constant
litigation. For these reasons, which are discussed in detail below, this proposal should be
rejected.

                           (i)     The Edison and ORA new entrant proposal violates Section 390(c).
            The first fatal flaw with the new entrant proposal is that it fails to comply with the
requirement of Section 390(c) that SRAC payments shall be based on the PX market-clearing
price. Under the ORA and Edison proposal, SRAC energy payments would not be based on the
PX clearing price; rather, as Edison‟s own testimony expressly states, SRAC payments would
“Be Based On The Variable Operation Cost Of The New Market Entrant.” Edison/Davis, Ex. 50,
at 43:13-15. If this blatant admission were not enough, Edison witness Jurewitz again admits the
violation of Section 390(c) when he states, in support of the proposal to base SRAC upon the
costs of a new market entrant rather than upon PX clearing prices: “The problem with using
these market-clearing prices as a reasonable proxy for the avoided cost of energy is that they
clearly reflect other components including the avoided cost of capacity as well as price impacts
associated with market power issues.” Edison/Jurewitz, Ex. 50, at 39:7-10. As CCC witness
Beach recounts: “The Edison / ORA proposal bases SRAC prices on the production costs of a
new merchant plant, not on the PX market-clearing price as the law requires.” CCC/Beach, Ex
7, at 12:5-7.

            Essentially, the ORA and Edison proposal (i) divides the energy costs of a hypothetical
new market entrant by recent historical PX prices to determine an “energy percentage” or “energy
value multiplier,” and (ii) multiplies this energy percentage or energy value multiplier by current
PX prices to determine SRAC payments. Edison/Stern, Tr. at 418:2-23. As Mr. Beach explains:
“In effect, all that Edison and ORA are using the PX price to do is to escalate the merchant
plant‟s energy costs over time.” CCC/Beach, Ex. 7, at 12:13-14. The new entrant pricing
proposal is illustrated in Exhibit 13, which clearly shows that, by including PX prices in both the
numerator (current PX prices) and denominator (historical PX prices) of the SRAC pricing
formula, PX prices are merely being used, as Mr. Beach states, as an escalation factor to adjust


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the energy costs of the new market entrant.

            The Legislature‟s use of the term “based on” the PX clearing price in Section 390(c)
clearly permits the Commission some discretion to consider factors other than only the PX
clearing price in designing its SRAC methodology in this proceeding. A plain reading of the
statute, however, requires that the PX clearing price be the basis of the methodology, not simply
an incidental component. Using the PX price solely as an escalation factor for the cost of the
new entrant simply does not meet the Legislature‟s requirement. One would not, for example,
conclude that a cost-based pricing formula that varies with changes to a Consumer Price Index
(“CPI”), is based on the CPI.

            In sum, under the Edison and ORA proposal, the basis for the SRAC pricing
methodology is the cost of the hypothetical new entrant. The new entrant proposal is not based
on the PX clearing price, which is used only as an escalation/deflation factor. The new entrant
proposal, therefore, violates Section 390(c) and should be rejected.

                          (ii)    The Edison and ORA new entrant proposal violates Section 390(d).
            The second fatal flaw of the new entrant proposal, which provides an entirely independent
and sufficient basis for its rejection, is that it violates Section 390(d). As discussed above,
Section 390(d) is clear in requiring that the value of capacity to be subtracted from the PX
clearing price is “the difference between the market clearing customer demand bid at the level of
generation dispatched by the independent Power Exchange and the highest supplier bid
dispatched.” The underlying premise of the new market entrant proposal, however, is that at
certain times there is considerable capacity value in PX clearing price and that such capacity
value, although not meeting the definition of the value of capacity set forth in Section 390(d),
must nevertheless not be paid to QFs already receiving contractually specified capacity payments.
See, e.g., Edison/Stern, Ex. 50, at 33-36 (asserting that there has been a value of capacity in the
PX clearing price); Edison/Jurewitz, Ex. 50, at 39:15-17 (arguing that the capacity value
observed during certain high price periods must not be paid to QFs with contractually-specified
capacity payments). In other words, the new entrant proposal is designed to ensure that QFs with
contractually-specified capacity payments are not paid a value of capacity in the clearing price
that is different from (i.e., greater than) the value of capacity set forth in Section 390(d). As

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such, the methodology fails to comply with Section 390(d).

            While ORA witness Linsey did attempt on cross-examination to reconcile his proposal
with the requirements of Section 390 (See, e.g., ORA/Linsey, Tr. 693:23-694-2), neither Edison
nor ORA made any pretense of attempting to comply with the requirements of Section 390(d) in
their prepared direct testimony. Instead, as discussed in Section II.B.2(iii) above, they chose to
assert that Section 390(d) violates PURPA and therefore should not applied in this proceeding.
Also as discussed in Section II.B.2(iii) above, Edison and ORA are wrong; the value of capacity
described in Section 390(d) accurately reflects the value of capacity in the PX clearing price and,
therefore, the value of capacity avoided by the utilities in the short run. As a result, the
application of Section 390(d) would not lead to a violation of PURPA. Also as discussed in
Section II.B.2(iii) above, even if the Commission were to believe that the application of Section
390(d) violates PURPA, the Commission must nevertheless enforce this provision until an
appellate court declares otherwise. The Commission, therefore, must reject the new
entrant proposal.

                           (iii)   The Edison and ORA new entrant proposal violates PURPA.
            As discussed above, the QF pricing methodology adopted by the Commission in this
proceeding must comply with PURPA, which requires that QFs be paid the purchasing utilities‟
full avoided cost. As reflected in the Scoping Memo (e.g., at 1) and in accordance with Section
390(c), the Commission is establishing in this proceeding the methodology for setting short-run
avoided cost payments to QFs; in particular to those QFs that are entitled to receive such SRAC
payments. As discussed below, the Edison and ORA new entrant proposal, however, does not
reflect the utilities‟ short-run avoided costs. Indeed, the Edison and ORA proposal would result
in payments that are substantially less than the utilities‟ short-run avoided costs. The Edison and
ORA proposal, therefore, violates PURPA.

            The failure of the Edison and ORA proposal to reflect the utilities‟ short-run avoided
costs is apparent for at least the following three reasons: (i) it is the cost of the least efficient
units in the system, not costs of new market entrants (which are presumed to be the most efficient
units), that will be avoided by QF purchases in the short-run; (ii) the Commission has previously
determined that, in setting short-run avoided cost payments, one does not consider new resource

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additions, rather one must rely upon the utilities‟ existing systems; and (iii) the new entrant
proposal is, if anything, a long-run avoided cost approach.

            As to short-run avoided costs in today‟s market, Mr. Beach testified: “In the short-run,
the energy costs that a QF avoids are the short-run marginal costs of the system to produce the
last MWh, as reflected in market-clearing supply bid of the last unit dispatched in the PX.”
CCC/Beach, Ex. 7, at 10:19-21. Mr. Beach explains that the new entrants upon which ORA and
Edison base their methodology are very unlikely to be the marginal unit dispatched in the PX, as
these units will be among the most efficient units available and will be expected to run as base-
load, infra-marginal units. Id. at 10:22-12:1. Because the new entrants will “rarely be on the
margin in the PX and will not change their generation when a QF comes on–line or goes
off-line . . . the energy production costs of a new merchant plant will not reflect the IOU‟s short-
run avoided energy costs in the PX.” Id. at 11:17-19.

            Stated another way, new merchant plants should be expected, in most hours, to be
running at full capacity because they are the most efficient units in the market. But for energy
purchases from QFs, additional energy would, in the short-run, be procured by the PX (and from
the PX by the utilities) from less efficient units that have costs far in excess of the costs of the
most efficient units in the system. It is the energy costs of the marginal units, whose production
would vary but for purchases from QFs, that reflect the utilities‟ short-run avoided costs and that
set the PX clearing price.14

            With respect to the Commission‟s prior SRAC policy, the Commission has repeatedly
held that SRAC energy payments should be determined based upon the utilities‟ existing system,
and not by relying on new resource additions. See, e.g., D.88-03-079, 1988 Cal. PUC Lexis 197
(March 23, 1988), at *34-39; D.88-11-052, 1988 Cal. PUC Lexis 745 (November 23, 1988), at
________________________

14
       Note that SRAC based upon the PX clearing price will not always result in payments to QFs
       that reflect the relatively high costs of inefficient units. In periods of low demand, very
       efficient units will clear the market and set the PX clearing price (and thus SRAC), resulting
       in very low SRAC payments to QFs.




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*96-97.15 See also, Edison/Jurewitz, Tr. 211:10-213:5 (agreeing that the “traditional pre-
restructuring method for calculating avoided cost of energy . . . used the existing system” and
did not include consideration of new generation units). CCC witness Beach supports the
Commission‟s prior determination, testifying: “In the short-run, one does not consider the
addition of new resources, such as new merchant plants.” CCC/Beach, Ex. 7, at 10:18-19. This
is because, as Edison witness Jurewitz agreed, the construction of new resource additions involve
long-range decisions. Edison/Jurewitz, Tr. at 218:25-220:16.

            Finally, Edison‟s own testimony demonstrates that the new entrant methodology is, if
anything, a long-run avoided cost proposal, not an SRAC proposal. As Dr. Jurewitz testified,
“the [new entrant] methodology can also stand on its own as a slightly more “generous” variation
of the Identified Deferrable Resource (IDR) methodology adopted by the Commission in 1986
and implemented in the BRPU auction in the early 1990s.” Edison/Jurewitz, Ex. 50, at 42:17-20
(citation omitted). The IDR methodology and the BRPU involved, as Dr. Jurewitz confirmed on
cross-examination, “long-run cost methodology.” Edison/Jurewitz, Tr. at 223:1-21. The IDR
methodology looked at the costs of a potential new resource addition (the Identified Deferrable
Resource), and thus was a long-run avoided cost methodology. Similarly, the new entrant
proposal, which Dr. Jurewitz himself refers to as a variation on the IDR methodology, also
reflects long-run avoided costs. As Edison itself argues in criticizing the line loss testimony of
Caithness Energy, L.L.C., “Section 390(c) requires the Commission to develop a market based,
short-run avoided cost of energy payment methodology for QFs” and it would be inappropriate to
adopt a methodology that “Confuses Long Run and Short Run Marginal Cost.”
Edison/Bergmann, Ex 72, at 8:20-22 (emphasis original), 8:5.


________________________

15
       Although the Commission did express a concern with relying exclusively on the existing
       system in these decisions, that concern was predicated on the fact that the QFs-In/QFs-Out
       methodology under consideration, in which the entire block of QF resources are removed
       from the production cost simulation, could yield unrealistic results. In the instant case,
       however, in which the PX clearing price is not determined using such a methodology, the
       Commission‟s concern would not be applicable.




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            In sum, the Edison and ORA new entrant proposal does not reflect the utilities‟ short-run
avoided costs. Instead it relies on the much lower costs of a hypothetical new entrant. Such a
proposal can only be described as a long-run avoided cost approach. Since PURPA requires
payments to QFs that are equal to the utilities‟ full avoided costs, and the QF payments at issue in
this proceeding are short-run avoided cost payments, the Edison and ORA proposal fails to
comply with PURPA.

                           (iv)   The Edison and ORA new entrant proposal would, if adopted, be
                                  extremely controversial and administratively burdensome.
            Even if the Edison and ORA new entrant proposal were not in violation of applicable
legal requirements, the Commission still should reject this approach to QF payments. The record
in this case is replete with evidence that implementing this proposal would be an administrative
nightmare.

            At the outset, it is worth recalling that one of the underlying themes of the Commission‟s
restructuring efforts was to replace administrative determinations with competitive forces
wherever possible. See, e.g., R.94-04-031/I.94-04-032 (the “Blue Book”), at 37. As it relies
almost entirely on administratively determined costs for a hypothetical new entrant, the Edison
and ORA proposal is a giant step directly in the wrong direction.

            What is worse, the administrative determinations needed to implement the new entrant
proposal promise to be complex, controversial and continuous. As Mr. Beach testified:

            Among the issues that would have to be determined include:

                  What plant or plants among the 15,000 MW‟s of merchant plants proposed in
                   California should be used to set SRAC prices? ORA admits that “technology and
                   resources will thus affect the new generator‟s marginal cost ratio to the PX price.”
                   ORA, at 47, lines 9-10.
                  What heat rate should be used? Table 1 on page 46 in Edison‟s testimony shows a
                   range of 6% between the low and high heat rates for the same plant (La Paloma).
                  What are the variable O&M costs? Edison‟s Table 1 shows a variation from $1.1
                   per MWh to $2 per MWh.
                  What gas cost is appropriate for the merchant plant‟s fuel cost? As shown in
                   Table 1 of Edison‟s testimony, gas costs for merchant plants can vary significantly


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                   by location and by the gas utility or pipeline that serves each plant. Edison‟s
                   testimony admits that the choice of which gas cost to use can cause the “energy
                   %” to vary by 10-15% due to this factor alone. Edison, at 47, lines 13-16. Gas
                   costs also vary over time: the Commission will recall the complexities and
                   controversies surrounding the “index methodology” used in the early-and mid-
                   1990s to determine avoided gas costs.
                  For determining the “energy %” or “energy value multiplier,” what base period
                   should be used to set the percentage or multiplier?

CCC/Beach, Ex. 7, at 13:10-29.

            While Edison witness Davis testified that the operating characteristics and costs of the
new entrant could be “easily calculated using burnertip gas prices, variable O&M expenses, and
heat rate” (Edison/Davis, Ex. 50, at 45:7-8), Dr. Davis‟ testimony is simply not credible. Just
with respect to determining gas costs, for example, Dr. Davis admitted on cross-examination that
he was not familiar with the various gas procurement options available to generators in
California. Edison/Davis, Tr. at 454:28-455:5. Dr. Davis also admitted that he did not even
consider the level of controversy encountered during the Commission‟s prior “index
methodology” for determining the utilities‟ gas costs. Id. at 460:16-19. With respect to his
proposal more generally, Dr. Davis stated simply that he “didn‟t consider the administrative
hassles” associated with implementing his proposal. Id. at 462:5-6.

            Lest the Commission forget, CCC/Watson have determined, from a review of the
applicable Commission decisions cited below, that there were no fewer than 53 separate protests
filed to the utilities‟ gas price postings under the index methodology between October of 1991
(when it was adopted in Decision 91-10-039) and December of 1996 (when it was replaced with
the current transition formula in Decision 96-12-028). Many of these protests raised multiple
issues. The Commission issued no fewer than 20 decisions in response to these protests,
agreeing, at least in part, with the QFs roughly half the time.16 As gas costs constitute a major



________________________

16
       See, e.g., D.92-03-022, D.92-05-022, D.92-08-040, D.92-09-038, D.93-01-040,
       D.93-02-015, D.93-03-046, D.93-10-071, D.94-02-016, D.94-04-040, D.94-09-035,
                                                                                         (continued…)

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component of the new entrants‟ costs, there is no reason to expect that there would be any less
controversy associated with the new entrant methodology; to the contrary, as competitive
opportunities in the gas market have increased, and continue to increase, there is likely to be
greater potential for dispute.

            CCC/Watson expect that Edison will point to the relative lack of controversy associated
with the current SRAC methodology, which relies on border gas price indices, in defense of its
proposal. The Commission should not be fooled. The existing methodology relies on changes in
previously agreed upon border-price indices to adjust a base SRAC amount. See, e.g.,
Edison/Davis, Tr. at 480:22-481:6. There is no controversy today because there is nothing to
argue about; the published border price indices are the published border price indices. Under
Edison‟s and ORA‟s proposed methodology, however, there is considerable room to argue about
what would be the gas costs experienced by the hypothetical new entrant, just as there was room
to argue about what indices best reflected the utilities‟ gas costs under the index methodology.

            In addition to the complexity associated with determining the gas costs of the new
entrant, the Commission should expect no less controversy with respect to the other new entrant
cost parameters. As reflected in Exhibit 27, illustrative new entrant costs presented in this
proceeding by Edison and ORA themselves vary by as much as forty-one percent. With this
much variation in the illustrative cost indicators already advanced, and CCC/Watson fully expect
that there would be many more proposed costs indicators if the new entrant proposal were
adopted, there is bound to be considerable disagreement among the affected interests.

            For this, and all of the foregoing reasons, the Commission should reject the Edison and
ORA new entrant proposal.

                   4.      The Commission should reject ORA’s heat rate cap proposal.
            ORA‟s heat rate cap proposal suffers from many of the same defects as the proposed new
________________________
(…continued)
       D.95-01-003, D.95-02-019, D.95-04-004, D.95-06-050, D.95-09-117, D.95-10-021,
       D.96-07-026, D.96-07-023, D.98-09-042.



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entrant methodology discussed above. In particular, as discussed in detail below, it violates
Section 390(d) and PURPA, and, if adopted, would be extremely controversial and
administratively burdensome. For these reasons, the proposal should be rejected.

                          (i)     The ORA heat rate cap proposal violates Section 390(d).
            ORA witness Sabino describes ORA‟s heat rate cap proposal as a “capacity subtractor”
approach. ORA/Sabino, Ex. 100, at 41:9. As Edison witness Stern states, Section 390(d) also is
a capacity subtractor methodology. Edison/Stern, Ex. 50, at 25:1-5. Just as Section 390(d)
specifies the value of capacity, if any, in the PX clearing price that is to be removed for setting
SRAC energy payments to QFs, ORA‟s “capacity subtractor would serve to identify the capacity
value within the PX clearing price.” ORA/Sabino, Ex. 100, at 41:19-20. This, however, is the
only similarity between ORA‟s proposal and the methodology required by Section 390(d).

            In essence, the ORA proposal applies a benchmark PX price, developed from the heat rate
of the least efficient units in the system, to current PX prices to determine SRAC energy
payments. As ORA witness Sabino states: “The amount by which the PX clearing price exceeds
the benchmark for the highest energy-based PX clearing price will act as a proxy for the capacity
value portion of the full PX clearing price.” ORA/Sabino, Ex. 100, at 42:11-13. In other words,
ORA proposes to determine the capacity value in the PX price as the difference between the full
PX price and the benchmark PX price developed according to ORA‟s formula.

            The methodology that ORA proposes to determine the value of capacity in the PX
clearing price clearly violates Section 390(d), which, provides that “[t]he value of capacity in the
clearing price, if any, equals the difference between the market clearing customer demand bid at
the level of generation dispatched by the independent Power Exchange and the highest supplier
bid dispatched.” As discussed above, the Commission must set an SRAC payment methodology
in compliance with Section 390(d); therefore, ORA‟s heat rate cap proposal must be rejected.

                          (ii)    The ORA heat rate cap proposal violates PURPA.
            ORA‟s proposed heat rate cap also should be rejected because it will not pay QFs the
utilities‟ full avoided cost as required by PURPA. As discussed above, short-run avoided energy
costs in today‟s market are defined by the energy costs of the marginal resources in the system


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(i.e., the resources that determine the PX market clearing price). While the ORA heat rate cap is
an improvement over the new entrant proposal in that it attempts to truncate PX prices based
upon the costs of the least efficient units (who are likely to be marginal units) as opposed to the
costs of the most efficient units (who are not likely to be marginal units), the heat rate cap
proposal still would result in payments that are lower than the utilities‟ full short-run avoided
energy costs.

            Stated simply, ORA‟s proposed heat rate cap fails to reflect the true energy costs of the
marginal bidders. For example, as ORA witness Sabino stated under cross-examination, there
are two kinds of variable operations and maintenance (“O&M”) costs experienced by generators,
fuel and non-fuel variable O&M costs. ORA/Sabino, Tr. at 711:10:-12. Ms. Sabino admitted
that ORA‟s proposed heat rate cap does not take into consideration non-fuel variable O&M costs.
Id. at 711:16-18. By failing to reflect non fuel variable O&M costs, the heat rate cap proposal
will establish an energy cost for the marginal unit that is below the unit‟s true energy costs and
thus yield a payment that is below SRAC in violation of PURPA.

            Similarly, Ms. Sabino stated that ORA‟s heat rate cap assumes that the marginal resource
burns natural gas. Id. at 711:19-21. Ms. Sabino agreed, however, that at times oil has been the
marginal fuel (and coal may have been the marginal fuel as well), and that the price of oil and
coal, on a Btu basis, do not equal the price of gas. Id. at 711:22-712:7. As such, if oil or coal
were to be the marginal fuel, ORA‟s proposed heat rate cap again would not account for the true
energy costs of the marginal bidder, as the heat rate cap will be based upon the cost of natural
gas. Further, Ms. Sabino admitted that ORA‟s heat rate cap reflects neither start-up costs nor the
cost of air emission credits (Id. at 712:6-11), resulting again in an understatement of the true
energy costs of the marginal bidder.

            Beyond these particular shortcomings with ORA‟s proposal, there is an underlying
methodological problem with ORA‟s approach that would lead to the undercompensation of QFs
in violation of PURPA. ORA‟s proposal is premised on the notion that when PX prices exceed
the expected energy costs of an inefficient unit on an hour by hour basis, there is significant
capital cost recovery that should not be included in SRAC energy payments. As Ms. Sabino
indicated, ORA relies, to determine the expected energy costs of the inefficient units, on average

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generator cost information. ORA/Sabino Tr., at 710:16-18. By applying average cost
information to hourly PX prices, even if the costs were computed accurately, the ORA proposal
will undercompensate QFs. In other words, the ORA proposal would cap PX prices that are
above the heat rate cap, while leaving unchanged PX prices below the heat rate cap, even if the
average PX price is below the heat rate cap.

            As CCC witness Beach explained, some marginal generators will have to recover, in only
a few hours of the year, energy costs that may be incurred on monthly or even longer basis.
CCC/Beach, Ex. 7, at 17:30- 18:10. Thus, in order to recover all of their energy-related costs,
their bids into the PX in any given hour may far exceed their average expected energy costs. Id.
Relatively high PX prices, even those well in excess of average marginal cost projections,
therefore, very well may reflect only energy costs. Id. Thus, by averaging the generators‟ costs
and applying these averaged costs to hourly PX data, the heat rate cap proposal will unduly
truncate PX prices and fail to compensate QFs for the utilities‟ full avoided energy costs in
violation of PURPA.17

                          (iii)   The ORA heat rate cap proposal would, if adopted, be extremely
                                  controversial and administratively burdensome.
            Just as the proposed new market entrant methodology would involve complex and
controversial administrative determinations, the proposed heat rate cap would be a regression for
________________________

17
          While it is undeniable that bidders will seek to recover more than just their variable costs
       from the market, the Commission should not be fooled by arguments that at high demand
       periods the marginal generators must be recovering considerable contributions towards
       capacity costs, otherwise they would go out of business. Generators will recover their fixed
       costs at times when their marginal-cost bids are considerably less than the market-clearing
       bid. They will maximize their fixed cost recovery by bidding at no more than their marginal
       costs in all hours, in order to maximize the number of hours in which they are dispatched.
       Moreover, in a real market, inefficient generators will go out of business; they will not
       recover their capacity costs from the market. In fact, in today‟s market, many of these
       marginal resources have RMR agreements, with fixed monthly payments, to ensure that they
       do not go out of business. With these fixed monthly payments designed to recover fixed
       capacity costs, these generators should not be expected to submit bids based upon anything
       other than their marginal costs.



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the Commission to the days of constant litigation over avoided cost payments. As ORA witness
Sabino herself acknowledged, “there are issues of implementation” associated with this proposed
method. ORA/Sabino, Ex. 100, at 42:30. Ms. Sabino listed the following issues: (i) access to
heat rate data is difficult as the utilities have divested nearly all of their gas-fired plants;
(ii) picking the least efficient units will be complex; (iii) the methodology assumes that the heat
rate embodied in the current SRAC formula is, and will remain, representative of the utilities‟
heat rate profile, an increasingly erroneous assumption as time goes on; and (iv) their would need
to be continued administrative proceedings to adjust the parameters relied upon by the
methodology. Id. at 42:30-43:17. In addition to the issues identified by Ms. Sabino herself, the
issues discussed above under subheading (ii) above with respect to start-up costs, marginal fuel,
air emissions credits and non-fuel O&M, also would need to be addressed, as would issues
involving other cost characteristics that undoubtedly would surface in the future.

            Because of the complexity associated with ORA‟s proposed heat rate cap methodology,
and for the other reasons discussed above, the Commission should reject this proposal.

                   5.     The Commission should reject ORA’s proposed SRAC subtractors.
            In addition to its flawed new market entrant and heat rate cap proposals, ORA also
suggests that the Commission should subtract from SRAC payments certain costs that are
incurred by the utilities as a result of the utilities‟ purchase of power from QFs. Originally, ORA
proposed to subtract all of the costs that the utility incurs in administering QF contracts and the
costs of firm transmission rights (“FTR”) that the utility incurred in order to honor the must-take
nature of QF resources. ORA/Linsey, Ex. 100, at 17:17-19:5. Upon reviewing Mr. Beach‟s
rebuttal testimony, however, ORA scaled back its proposal to involve only the FTR costs and the
costs that the utility incurs for scheduling and dispatch, meter reading, making up settlement
statements and sending out payments. ORA/Linsey, Tr. at 707:19-26.

            The reasoning in Mr. Beach‟s rebuttal testimony that ORA witness Linsey found
persuasive is that the costs incurred by the utility to administer QF contracts do not vary with QF
purchases in the short-run and, as such, they are not appropriately credited against short-run
avoided costs. CCC/Beach, Ex. 7, at 21:15-20; ORA/Linsey, Tr. at 707:19-26. This logic,
however, applies to all of the costs that ORA originally proposed to subtract from QF payments,

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including the FTR costs and the other administration costs referred to above. Upon cross-
examination, for example, Mr. Linsey acknowledged that meter-reading costs will not vary based
upon how much a QF produces. ORA/Linsey, Tr. at 708:1-8. As Mr. Linsey agreed, if a QF
generated 30 MW or 40 MW in any given period the utility is going to incur the same cost to
read that QF‟s meter. Id.

            Although Mr. Linsey continued to assert that the cost of preparing settlement statements
may be related to the amount of QF production, his testimony simply is not credible. The utility
is going to incur the same costs to prepare a settlement statement with high generation numbers
as with low generation numbers. Similarly, the cost of sending out a QF payment will be the
same regardless of the amount of the payment, and the cost of scheduling and dispatching a given
QF will be the same irrespective of whether or not the QF is producing more or less electricity at
any given moment. As well, once Edison has procured FTRs for a given QF, the related costs are
sunk. In the short-run, these FTR costs will not vary based upon the amount of the QF
generation. As such, they are not legitimately applied as offsets to SRAC payments.

                   6.      The Commission should adopt the CCC’s proposed “market basket”
                           approach to revisiting the SRAC payment methodology.
            The Scoping Memo includes as an issue for consideration in this proceeding “identifying
situations that would lead to reconsideration of the adopted PX-based SRAC.” Scoping Memo
at 2. One approach to this issue would be to rely upon the functioning properly criteria that the
Commission adopts, and reopen the SRAC payment methodology if the PX fails to meet these
criteria on an ongoing basis. This is the approach espoused by PG&E. PG&E/Pappas, Ex. 52, at
7.

            While the CCC agrees that, if the PX is not functioning properly in accordance with the
standards adopted by the Commission, the PX should not continue to serve as the basis for
SRAC payments to QFs. Nevertheless, it may not be practical for the parties and the
Commission to continuously monitor the PX‟s compliance with the adopted functioning properly
criteria. As a result, the CCC proposes that the Commission compare PX prices to a
representative sample of other market price indices to determine whether the PX continues to be
a fair reflection of market prices. CCC/Beach, Ex. 3, at 28:16-29:8 If there are significant


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deviations between the PX prices and the energy costs revealed by other market price indices,
then the Commission should, upon a motion from any affected party, evaluate whether the PX is
indeed functioning properly for the purpose of determining SRAC payments.

            In addition, the utilities should be required to report, at least annually, the sources of their
purchases. To the extent that they purchase significant power from sources other than the PX,
closer scrutiny as to the proper functioning of the PX for SRAC purposes and whether the PX
market-clearing price continues to reflect the utilities‟ avoided costs may be warranted.
CCC/Beach, Ex. 3, at 29:9-24.

            The only criticism of the CCC‟s proposal came from SDG&E witness Schelhorse.
Dr. Schelhorse argued that requiring the utilities to report the sources of their purchases conflicts
with the Commission‟s trend towards less reporting obligations and would subject the utilities to
a competitive disadvantage. Dr. Schelhorse states that this requirement only should be imposed
if it is imposed on all market participants. SDG&E/Schelhorse, Ex. 54, at 12:17-13:2.
Dr. Schelhorse‟s criticisms are invalid.

            The CCC has no interest in requiring unnecessary reporting by the utilities. In this case,
however, the Commission and interested parties have a right to be secure that SRAC energy
payments are being appropriately set. When prices from one given market institution are being
used to determine SRAC, and these prices are intended to reflect more broadly the price at which
the utilities are assumed to be purchasing power in the market from all short-run sources, it is
essential to monitor whether the utilities are systematically or substantially avoiding the
designated market institution for their actual purchases. If so, as explained above, the PX price
may not accurately be reflecting SRAC. As to the competitive advantage claim, it is very
possible that the utilities will be required to report on their purchases in order to set procurement
rates for bundled retail customers. Even if the utilities do not otherwise report their purchases,
and even if the Commission finds this information to be confidential, the Commission could
require an appropriate non-disclosure agreement to the executed prior to receipt of the data.
Finally, it would not make sense to require all market participants to report on their purchases.
The only reason to require such reporting is to ensure that SRAC is being appropriately set. To
try to level the playing field by requiring additional reporting from other market participants

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would be a waste of resources; a non-disclosure agreement would be a much more
appropriate mechanism.

            C.     As-Available Capacity Pricing.
                   1.     Introduction and Summary.
            Although not within the scope of Section 390, which relates to SRAC energy payments,
the Scoping Memo solicited recommended modifications to the methodology for setting as-
available capacity payments. Scoping Memo at 2. Only two distinct proposals for as-available
capacity payments were made in this proceeding.

            Not surprisingly, the utilities and ORA argue that as-available capacity payments to QFs
should be limited to the value of capacity, if any, reflected in the PX market clearing price, which
they assert is an “all- in price” for both energy and capacity. See, e.g., SDG&E/Schelhorse,
Ex. 51, at 11:10-12:10; Edison/McCarthy, Ex. 50, at 51:18-52:2; PG&E/Pappas, Ex. 52, at 8-9;
ORA/Sabino, Ex. 100, at 48:14-26. Because, a number of years ago, the CCC entered into a
settlement with PG&E providing for as-available capacity payments to be set equal to the value,
if any, of capacity in the PX market clearing price, and because PG&E has lived up to its
commitments in the settlement, the CCC is willing to accept this methodology for as-available
capacity payments in PG&E‟s service territory. See, e.g., CCC/Beach, Ex. 3, at 32:5-33:4.

            For QFs in SDG&E‟s service territory, for whom there was no settlement on as-available
capacity pricing, and for QFs in the service territory of Edison, which has voluntarily elected to
repudiate its commitments in a settlement similar to the PG&E settlement, however, the
Commission should set as-available capacity payments equal to the true avoided costs associated
with as-available capacity in today‟s market. This value is best reflected in the value of spinning
and non-spinning reserves in the ISO‟s ancillary services market. CCC/Beach, Ex. 3, at 33:5-
35:26. As a result, for QFs in SDG&E‟s and Edison‟s service territory, the CCC proposes that
as-available capacity payments should be set at the simple average of the hourly prices for
spinning reserves and non-spinning reserves.




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                   2.      While the CCC agrees that the PX price is an all-in price, it is not the
                           only source of compensation for as-available capacity in the market.
            Practically the only rationale offered by the utilities and ORA for the proposition that as-
available capacity payments should be set at the value of capacity in the PX clearing price is their
assertion that the PX price is an “all-in price,” reflecting the value of both capacity and energy.18
See, e.g., SDG&E/Schelhorse, Ex. 51, at 11:10-12:10; Edison/McCarthy, Ex. 50, at 51:18-52:2;
PG&E/Pappas, Ex. 52, at 8-9. ORA/Sabino, Ex. 100, at 48:18-22. The CCC does not disagree
that for bidders that trade exclusively in the PX, the PX will reflect the only compensation such
bidders will receive for both capacity and energy. As such, for bidders that were to trade
exclusively in the PX, the PX clearing price will reflect an “all-in price.”

            However, it is not disputed that in today‟s market, generators have options beyond selling
exclusively in the PX; they may sell power, for example, into the ISO‟s ancillary services market,
or enter into RMR contracts with the ISO. See, e.g., Edison/Jurewitz, Tr. at 210:17-211:9.
Similarly, the utilities incur costs beyond simply PX costs; they pay the ISO for ancillary services
costs and for RMR costs. SDG&E/Schelhorse, Tr. at 283:21-284:3. As even SDG&E witness
Schelhorse acknowledged, to the extent that purchases from QFs allow the utility to avoid as-
available capacity costs in the ISO‟s ancillary services market or in RMR contracts, these
avoided costs must, under PURPA, be paid to QFs entitled to receive as-available capacity
payments. Id. at 284:10-285:8. Thus limiting the inquiry to the value of capacity in the PX
unduly fails to reflect the true value of capacity in today‟s market.19

________________________

18
           ORA also argues that SO1 QFs have less incentives to deliver power, and thus deliver
       inferior service, than do PX participants. ORA/Sabino, Ex. 100, at 48:22-26. First, this
       comment would seem to indicate that the capacity value in the PX should not be the basis for
       as-available capacity payments. Second, as discussed by CCC witness Beach, this statement
       is incorrect. SO1, and all QFs delivering as-available capacity, have stronger incentives to
       deliver than do PX participants, who might actually profit at times from failing to deliver
       into the PX. CCC/Beach, Ex. 3, at 35:1-8. See also ORA/Linsey; Tr. at 697:27-70:27.
19
       Unlike SRAC energy payments, which according to Section 390(c) are to be based upon the
       clearing price of the PX, there is no limitation on considering non-PX price indicators in
       setting as-available capacity payments.



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            As the Commission already has recognized in a decision addressing, in part, the need to
reconsider as-available capacity payments to QFs, the value of capacity in today‟s market will be
reflected in the ISO‟s ancillary services markets. In Decision 96-10-036 the Commission stated:
“The unbundling of ancillary services like spinning and non-spinning reserve will provide new
market based measures of the value of capacity.” D.96-10-036, at 35. SDG&E witness
Schelhorse confirms the Commission‟s position, stating that in today‟s market the ISO, not the
PX, is the provider of reliability services (SDG&E/Schelhorse, Tr. at 283:21-23), services that
are typically associated with capacity. Even Edison witness McCarthy acknowledges that “the
ancillary services market may represent a possible starting point for a proxy for as-available
capacity.” Edison/McCarthy, Ex. 53, at 34:15-16.

            The question then, is whether as-available QFs allow the utility to avoid ancillary services
costs, RMR costs and other capacity costs in today‟s market, beyond simply the capacity
component of the PX clearing price. As CCC witness Beach testified, the answer is yes. Mr.
Beach explains that, when determining its need for RMR services, the ISO assumes that as-
available QFs are operating at historical levels. CCC/Beach, Ex. 3, at 31:8-15. But for this
assumption, the ISO would need to procure additional RMR generation. Id. In addition, as Mr.
Beach states, “the population and diversity of as-available QFs is large enough such that ISO
does not procure operating reserves (i.e., spinning and non-spinning reserves) to cover
fluctuations in the output of such units.” Id. at 31:9-32:2. To the extent that as-available QFs
were not in the resource mix, the ISO may have to purchase additional operating reserves. Id.
As a result, QFs providing as-available capacity to the utilities must be compensated for the
value of the capacity that they permit the utility to avoid.

                   3.      The appropriate measure of as-available capacity payments for QFs
                           in SDG&E’s and Edison’s service territories is the average of the
                           prices for spinning and non-spinning reserves.
            While it will be extremely difficult to determine the value of avoided RMR costs, the
Commission can, as it indicated in Decision 96-10-036, look to the ISO‟s ancillary services
markets as a reasonable measure of the market value, and thereby the avoided cost, of as-
available capacity. As CCC witness Beach testified:



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            The ISO procures roughly 50% of its operating reserve requirement as spinning
            reserves and 50% as non-spinning reserves. Accordingly, I propose a 50/50
            weighting of hourly spinning and non-spinning reserve prices as the measure of
            as-available capacity for SDG&E. This approach reflects the market value of the
            capacity that the ISO procures in each hour to meet short-term changes in load on
            “its system. As discussed above, the aggregate production of as-available QFs
            allow the ISO (and thus each IOU) to avoid incurring additional operating reserve
            costs to meet changes n production from individual QFs. In my view, the hourly
            prices for operating reserves provide the most visible and accurate measure of the
            value of short-term capacity on the ISO grid. This recommendation is fully
            consistent with the Commission‟s observation in D 96-10-036 that the prices for
            ancillary services such as spinning and non-spinning reserves „will provide new
            market-based measures of the value of capacity.

CCC/Beach. Ex. 3, at 33:9-20.

            Edison witness McCarthy objected to the CCC‟s proposal to use the prices in the ISO‟s
ancillary services market as the measure for as-available capacity payments, arguing that
generators in the ancillary services market commit to providing energy when needed, while as-
available QFs make no commitment to generate at any particular time. Edison/McCarthy, Ex.
53, at 34:21-23. The CCC does not disagree with Mr. McCarthy that the service provided by
individual as-available QFs is not identical to the service provided in the ISO‟s ancillary services
markets. Mr. McCarthy‟s objection to using values in the ancillary services market is
nevertheless misplaced for at least two reasons.

            First, regardless of whether individual as-available QFs are providing a service that is
identical to that provided in the ISO‟s operating reserves markets, or under RMR contracts, as-
available QFs allow the utility to avoid costs associated with operating reserves and RMR
service. As such, they are entitled to fair compensation for the costs that they permit the utility to
avoid, even if the underlying services are not identical. Second, even if we accept the premise of
Mr. McCarthy‟s statement, his argument is besides the point. As Mr. McCarthy himself
acknowledges, the use of the ISO‟s ancillary services prices as the determinant for as-available
QFs may be viewed as a reasonable market-based proxy for the value of as-available capacity
provided by QFs. The Commission has long established as-available capacity pricing based upon
a proxy approach, in particular, by using the costs of a simple cycle combustion turbine. As
Edison witness Jurewitz stated: “In the past, the Commission consistently determined that the


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best proxy for such a „pure capacity‟ resource is the current fixed cost of a simple-cycle
combustion turbine.” Edison/Jurewitz, Ex. 50, at 41:9-12; Edison/Jurewitz, Tr. at 221:18-20.

            In today‟s market, the Commission has the fortunate opportunity to replace the existing
administratively determined proxy with a market-based measure of as-available capacity. As a
result, the Commission should adopt, as the as-available capacity payment for QFs in SDG&E‟s
and Edison‟s service territory, the simple average of the ISO‟s prices for spinning reserves and
non-spinning reserves.

            D.     Line Loss Factors.
                   1.      Introduction and Summary.
            PURPA requires the Commission to include in avoided cost payments to QFs, to the
extent practicable, “the costs or savings resulting from variations in line losses from those that
would have existed in the absence of purchases from a qualifying facility, if the purchasing
electric utility generated an equivalent amount of energy itself or purchased an equivalent amount
of electric energy or capacity.” 18 CFR 292.305(e)(4). As reflected in the Final Report on Line
Loss Workshop in this proceeding, dated April 7, 2000 (“Workshop Report”), the Commission
has long struggled with the difficulties associated with determining avoided line loss costs.
Workshop Report at 3-6. See also D.99-03-021, at 7 (“The Commission has long recognized that
determining the impact of QFs on line losses is a difficult and complex process.”). Nevertheless,
the Commission has solicited proposals from the parties in this proceeding on whether, and if so,
how, to revise the existing QF line loss factors.

            Five parties submitted testimony on line loss issues, yielding three primary proposals, one
fall-back proposal and one double fall-back proposal. Edison, SDG&E and ORA each offered,
as their primary proposal, to set the transmission level line loss factor (“TLF”) for each QF equal
to the ISO‟s generation meter multiplier (“GMM”) for that QF. See, e.g., Edison/Bergmann, Ex.
68, at 1:11-14; SDG&E/Nelson, Ex. 69, at 2:2-9; ORA/Linsey, Ex. 104, at 1:5-8. As a fall-back
position, SDG&E and ORA request that the Commission set the TLF for all QFs equal to 1.0 if
the Commission decides not to adopt the GMMs as the TLF. SDG&E/Nelson, Ex. 69, at 2:2-9;
ORA/Linsey, Ex. 104, at 1:9-13. In the event that this fall-back position is not adopted, SDG&E



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recommends that the Commission adopt the TLFs produced by its recent line-loss study for QFs
on its system. SDG&E/Nelson, Ex. 69, at 2:2-9.

            Caithness Energy, L.L.C., proposed that the Commission retain the existing TLFs at this
time. Caithness/El-Gasseir/Clark, Ex. 19, at 11.

            The CCC proposes that the Commission set the TLFs equal to what is commonly referred
to as “unscaled GMMs” for all QFs, except to the extent that a QF that is located far from the
load center (“Remote QF”) serves a load also far from the load center but near to the QF (“Local
Load”). To the extent that Remote QFs serve Local Loads, the CCC proposes a distinct TLF
methodology to better account for the true avoided line-loss costs associated with the QF‟s local
generation.

            As discussed below, setting the TLFs at the GMMs, as proposed by the utilities and ORA,
will violate PURPA by underpaying QFs located relatively close to load centers for the line loss
costs that they allow the utility to avoid and by underpaying Remote QFs serving Local Load.
Use of the GMMs also will fail to send accurate price signals to QFs, violating the Commission‟s
long-standing policy for avoided-cost pricing. These same fundamental defects also are true, and
even more pronounced, with respect to SDG&E‟s and ORA‟s fall-back proposal of setting the
TLFs equal to 1.0. SDG&E‟s ultimate fall-back proposal, to set the TLFs based upon SDG&E‟s
recent line loss study, has more potential, but also would violate PURPA because SDG&E
improperly adjusts downward the losses that its own study shows are avoided by QF generation.

            The CCC‟s proposals on the other hand, would establish TLFs based upon the same ISO
GMM data used by the utilities and ORA, but would refine that data to reflect correctly the line
loss savings, or costs, to the utilities of QF generation. The CCC‟s methodology also would send
the most accurate price signals to QFs of any of the proposals in this case. Accordingly, the
Commission should adopt the CCC‟s proposed TLF methodology.

                   2.     Setting the TLFs equal to the GMMs would violate PURPA and send
                          inaccurate price signals to QFs.
            This is the second time in less than two years that the Commission has been asked to
adopt the GMMs as the TLFs. Obviously, the first time it was asked, in A.98-06-045, the

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Commission rejected this proposal. See D.99-03-021. The Commission should do so again in
this proceeding.

            While the GMMs may be fine for the purpose for which they were designed (although
there is considerable controversy as to even that point), they were not designed to, and do not,
reflect the line loss costs or savings attributable to QF generation. See, e.g., CCC/Beach, Ex. 17,
at 5:8-11:17. See also Workshop Report at 24 (“Another problem with GMMs is that they are
designed for something different from what is needed to conform to PURPA avoided cost
principles”). In order to comply with PURPA, the TLF methodology adopted by the
Commission should reflect the transmission level line loss costs that the utility avoids or incurs
as a result of its purchasing an additional increment of QF generation. CCC/Beach, Ex. 17, at
11:7-9. The primary problem associated with using GMMs as the TLFs is that the GMMs do not
accurately reflect the incremental or marginal impact that a given generator has on system losses.
Id. at 11:9-11.

            Each generator‟s GMM is derived by the ISO from marginal loss factors, but the marginal
loss factors are scaled down so that the aggregate of all GMM-adjusted deliveries on the system
are set equal to the actual system loads. Id. at 6:1-7:17. By scaling the marginal loss factors, the
ISO converts the factors from a true marginal loss determinant to a marginal-cost based means of
allocating total system losses to generators for settlement purposes. In other words, the scaled
marginal loss factors (i.e., the GMMs) do not reflect the true impact that generators have on
system losses. Id. at 7:29-31. As such, the GMMs do not reflect the line loss costs that the
utility avoids (or incurs) as a result of QF purchases. As the Workshop Report states: “Another
argument against GMMs is that they are based on scaled marginal load [sic] factors, instead of
full marginal loss factors, and thus do not reflect the full effect on system line losses.” Workshop
Report at 24.

            As ORA witness Linsey notes, the ISO‟s scaling process will reduce both the marginal
costs and marginal savings associated with line losses, relative to unscaled loss factors.
ORA/Linsey, Ex. 104, at 1-3. In other words, QFs that actually add to system losses would
benefit through the scaling, because the amount by which they are considered to add to such
losses is reduced, while QFs that serve to diminish or permit the avoidance of system losses

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suffer from the scaling, because the amount by which they avoid system losses is reduced. While
ORA witness Linsey believes that this is reasonable, his belief cannot be reconciled with PURPA
or with the Commission‟s policy on avoided cost pricing.

            PURPA entitles each and every QF to receive payments equal to costs that such QF
allows the utility to avoid, included avoided line loss costs. As discussed above, PURPA entitles
QFs to receive payments based upon the utility‟s full avoided costs. PURPA does not entitle the
Commission to pay one QF less than the utility‟s full avoided cost so as to pay another QF more
than the utility‟s full avoided cost. To the extent that using the GMMs as the TLFs fail to reflect
the utilities‟ full avoided costs associated with QF generation, the GMMs fail to comply with
PURPA and must be rejected.

            SDG&E‟s own study of the line loss costs avoided by QFs on its system provides
irrefutable evidence that use of the GMMs would underpay QFs in violation of PURPA.
According to SDG&E‟s own study, which the sponsor Mr. Abed described as “accurately
reflect[ing] line losses on SDG&E‟s system,” (SDG&E/Abed, Tr. at 901:10-12) adopting the
GMMs would underpay the four transmission level QFs on its system by $420,000 per year.20 In
fact, as Mr. Beach has testified that SDG&E substantially under-represents the TLFs that its own
study yields (as discussed further below), the underpayment to SDG&E QFs by using the GMMs
would be substantially higher. CCC/Beach, Ex. 21, at 10:3-19.

            In addition to violating PURPA, use of the GMMs would not send accurate price signals
to QFs. CCC/Beach, Ex. 17, at 11:14-15. QFs that reduce system losses will not receive the full
incentive to generate that is warranted, while QFs that contribute to system losses will have too
________________________

20
       Table 12 in Mr. Abed‟s testimony compares the relative savings to the utility if the existing
       TLFs were replaced with the TLFs produced by the SDG&E study and if the existing TLFs
       were replaced with the GMMs. The difference between the savings under the TLFs
       produced by the SDG&E study and the savings using the GMMs reflects the difference in
       payments that would be made to QFs using the different methodologies. The difference
       shown in Table 12 (as corrected at the hearings by statement of counsel) is $420,000 per
       year. SDG&E/Sullivan, Tr. at 967:28-968:2.




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great an incentive to generate than is warranted. Again, SDG&E itself is the best source of
information condemning the use of GMMs. SDG&E witness Nelson testified that Sempra,
SDG&E‟s parent company, has filed comments at FERC that are critical of the GMMs, and that
he did not disagree with these comments. SDG&E/Nelson, Tr. at 882:20-883:7. The relevant
portion of these comments are contained in Exhibit 24. The heading for the relevant portion,
which reflects the substantive discussion that follows is: “SCALED MARGINAL PRICING OF
LOSSES DISTORTS ENERGY PRICES AND UNDERMINES COMPETITION.” Ex. 24, at
12. Agreeing with the CCC‟s position in this proceeding, the Sempra comments go on to state:
“The scaling of marginal losses subsidizes generation distant from load, distorting generator
location decisions and raising the total cost of meeting load.” Id. at 12-13.

            As discussed above, the Commission has a long-standing policy of attempting to send
accurate price signals to QFs as part of its SRAC payment methodology. Since the GMMs do
not fully reflect the impact on losses associated with individual generators, the GMMs do not
send accurate price signals to QFs and should not be adopted as the TLFs in this proceeding.21

                   3.     Setting the TLFs equal to 1.0 would be even worse than adopting the
                          GMMs.
            For all the reasons articulated above in connection with the shortcomings of the GMMs,
ORA‟s and SDG&E‟s proposed fall-back position to set the TLFs equal to 1.0 also should be
rejected. Using a TLF of 1.0 assumes that QFs neither contribute to nor reduce line losses on the
system. If there is one thing that we can know for certain, it is that this assumption is incorrect;
QFs have an impact on system losses. According to SDG&E‟s analysis, using a TLF of 1.0
would result in a $174,000 annual underpayment to the four transmission level QFs on SDG&E‟s

________________________

21
       As CCC witness Beach recognized, however, the GMMs are not without some redeeming
       value: they are calculated every hour for sizeable QFs; an independent entity (the ISO)
       calculates them; and the ISO makes them readily available. CCC/Beach, Ex. 17, at 11:18-
       21. These same benefits, however, may be captured using the CCC‟s proposed TLF
       methodology, which is based upon the ISO‟s GMM data, and which complies with PURPA
       and the Commission‟s goal of sending accurate price signals to QFs.




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system. SDG&E/Abed, Tr. at 904:10-13.22 Therefore, simply using a TLF of 1.0 would violate
PURPA. It also would have absolutely no price signal, a clear violation of Commission policy.

            The only justification offered in support of using 1.0 as the TLF is that it is easier than
using the other measures proposed. Id. While ease of implementation is certainly a laudable
goal, it simply does not justify failing to pay QFs for the losses that they allow the utility to
avoid, as required by PURPA. As a result, the ORA and SDG&E fall-back position should be
rejected.

                   4.      SDG&E’s methodology for converting the results of its line loss study
                           into TLFs improperly reduces the proposed TLFs.
            As referred to above, SDG&E conducted a study of the transmission level line loss costs
that QFs on its system allow the utility to avoid. As a final fall-back position, if the Commission
were to reject the GMMs and the 1.0 proposal, SDG&E proposes that the Commission employ
the TLFs yielded by its study. SDG&E/Nelson, Ex. 69, at 3:14-19; SDG&E/Abed, Ex. 70,
at 18:18-19 (proposing that the 1.0 factor be used ahead of the TLFs produced by SDG&E‟s
study for simplicity).

            As the unchallenged testimony of Mr. Beach reflects, however, SDG&E improperly
determined the TLFs by double counting the impact of system load variations. CCC/Beach, Ex.
21, at 8:2-10:5. This error substantially understates the TLF that should be applied to QFs using
SDG&E‟s own data. Id. In fact, if the error is corrected, as Mr. Beach testified, the appropriate
TLFs would be similar to the TLFs proposed by the CCC. Id. at 10:5-19.

            Because of the significant error in SDG&E‟s proposed TLFs, the Commission should not
adopt them as the TLFs in this proceeding.



________________________

22
       At the hearings, by a statement of counsel, the figures in Table 12 were corrected, yielding a
       replacement of the $124,000 figure referenced in Mr. Abed‟s testimony with a $174,000
       figure.




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                   5.      The Commission should set the TLFs equal to unscaled GMMs
                           (except to the extent that a Remote QF serves Local Load).
            Having established that it is the scaling of the GMMs by the ISO that distorts the
marginal-cost nature of the ISO‟s line loss factors, and as a result, prevents the GMMs from
legitimately being used as the TLFs, the obvious solution for the Commission in this proceeding
is to unscale the GMMs and restore them to their proper marginal-cost foundation. This is
exactly what the CCC proposes in this proceeding as the basic approach to the TLFs. In his
direct testimony on line loss issues, Exhibit 17, Mr. Beach explains how the ISO‟s GMMs may
be unscaled to yield true marginal cost line loss factors that can be used as the TLFs by the
Commission. Ex. 17, at 13:1-15:20.

            Using unscaled GMMs will fully account for the incremental line-loss costs and savings
that result from QF generation, in compliance with PURPA, and will send accurate price signals
to QF, in accordance with Commission policy. Id. It will allow for hourly calculations based
upon the very same data that the ISO uses to determine the GMMs. Even Edison agrees that the
CCC proposal “incorporates a number of the advantages of GMMs” and will “encourage [an]
efficient allocation of existing resources and foster the development of a more efficiently
functioning market over time.” Edison/Bergmann, Ex. 72, at 2:2-3; Edison/Mayfield, Ex. 72, at
11:25-26. In fact, Edison believes that the CCC‟s proposal may actually benefit Edison‟s
ratepayers. Edison/Bergmann, Ex. 72, at 2:5-7; Edison/Mayfield, Ex. 72, at 11:14-15.

            The only witness to criticize the use of unscaled GMMs was SDG&E witness Nelson.
Mr. Nelson argues, first, that two critical determinants in the CCC‟s methodology, the ISO
scaling factor and the ISO system-average GMM are not published by the ISO and there is no
proceeding pending in which the ISO would publish the information. SDG&E/Nelson, Ex. 73,
at 1:7-12. Upon cross-examination, however, Mr. Nelson did not know whether the ISO
considered the information to be confidential, and could not identify any reason why the ISO
would not make this information available if asked. SDG&E/Nelson, Tr. at 886:8-28. Mr.
Beach, however, testified that the ISO should be willing to make this information available.
CCC/Beach, Ex. 17, at 15:16-17. Even if the information was not made public by the ISO, there
is enough information about the ISO‟s GMM methodology already in the public domain to allow



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for a reasonable approximation of the necessary values. See, e.g., SDG&E/Nelson, Tr. at 887:1-
21 (describing how one could calculate the ISO system-average GMM); CCC/Beach, Ex. 17, at
6, footnote 2 (referring to scaling factors released by the ISO in a recent report to FERC).23

            Mr. Nelson argues, second, that there is “no operational or factual basis to support”
unscaling the GMMs. SDG&E/Nelson, Ex. 73, at 1:27-28. In light of Sempra‟s own criticisms
of the scaling of the GMMs discussed above, with which Mr. Nelson does not disagree,
Mr. Nelson should understand the bases supporting the CCC‟s proposal. Stated simply,
unscaling the GMMs will yield TLFs that fully account for the marginal impact, and thus,
avoided costs, associated with QF generation, and that send appropriate price signals to QFs.
Except to the extent that a Remote QF serves Local Load, as discussed below, the Commission
should adopt the CCC‟s unscaled GMM proposal as the methodology for establishing the TLFs.

                   6.      The Commission should adopt the CCC’s proposed TLF methodology
                           for Remote QF generation serving Local Load.
            The GMMs are produced by the ISO using a power flow model of its system that purports
to determine the impact on system losses of adding one additional MW of generation from each
generator modeled. CCC/Beach, Ex. 17, at 6:2-5. A critical assumption underlying the ISO‟s
GMM methodology is that the one additional MW of generation added serves load spread
proportionately to demand across the entire ISO grid. Id. Reliance on this assumption, which
clearly does not reflect the physical reality of system power flows, was one of the primary
reasons why the Commission rejected the use of GMMs as the TLFs in Decision 99-03-021. As
the Commission concluded in that decision: “The methodology used to derive GMMs spread
demand proportionately throughout the ISO grid. This approach may not accurately measure
marginal line losses on a utility system (e.g., SDG&E) for the purpose of assessing the impact of
QFs.” D.99-03-021, at 20 (Conclusion of Law #7).


________________________

23
       In fact, as discussed above, Edison witness Mayfield testified that the system average GMM
       was roughly 0.98. Edison/Mayfield, Tr.. at 1008:28-1009:2




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            One instance in which the ISO‟s GMM assumption clearly would not accurately reflect
the marginal losses on the utility‟s system, as Mr. Beach testified, is in the case of a Remote QF
serving Local Load. CCC/Beach, Ex. 17, at 17:2-13. Remote QFs have low GMMs because the
ISO‟s GMM methodology assumes that practically all of their generation travels relatively long
distances to serve load as compared to QFs located close to the load centers. To the extent that a
Remote QF serves a Local Load, however, its generation actually travels a relatively short
distance and the ISO‟s assumption that its generation serves load spread proportionately across
the entire grid overstates the losses attributable to the QF. Id. From an avoided cost perspective,
this would be stated as follows: but for the Remote QF serving the Local Load, power would
have to travel from a greater distance to serve this load. Thus, the Remote QF allows the utility
to avoid losses that are not accounted for by the GMMs, as the GMMs do not credit the QF for
the amount of its generation that actually goes to serve the Local Load.

            There was a discussion of this problem at the line loss workshop in this proceeding, and
the Workshop Report reflects the problem associated with the ISO‟s GMM assumption for
Remote QFs serving Local Load. As stated in the Workshop Report: “Exemplifying this
concern is the hypothetical of the remote QF serving a local load. In the hypothetical example,
the remote generator does appear to be treated unfairly by the GMM method, however
participants could not identify a real world case which embodies the characteristics of the
hypothetical.” Workshop Report at 24. In fact, ORA witness Linsey agreed in his prepared
rebuttal testimony that where the Remote QF‟s generation is in approximate balance to the Local
Load, “the assumption that load is proportionately distributed in the GMMs would indeed
overstate the GMM adjustment applicable to that remote QF.” ORA/Linsey, Ex. 105, at 1:6-10.
On cross-examination, Mr. Linsey agreed that the inaccuracy of the ISO assumption is not
limited to a hypothetical situation in which the generation and load is in approximate balance, but
applies even if there is more or less Remote QF generation than Local Load. ORA/Linsey, Tr.
938:6-940:12. Of course, as Mr. Linsey indicated, to the extent that the Remote QF generation
greatly exceeds the Local Load, the ISO GMM assumption is less inaccurate than if all or most of
the Remote QF generation serves the Local Load. Id. at 940:9-12.

            In light of the fact that the ISO‟s GMM assumptions will erroneously overstate the losses


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associated with Remote QFs to the extent that they serve Local Load, the CCC proposes a
distinct TLF methodology for QFs in this position. In Exhibit 17, Mr. Beach presents the CCC‟s
proposal for calculating a separate line loss factor that would apply to a Remote QF to the extent
that it serves Local Load. CCC/Beach, Ex. 17, at 17:14-18:17. This line loss factor fairly
accounts for the true marginal loss impact of such a QF‟s generation, unlike the GMMs. Id. To
the extent that a Remote QF‟s generation serves a local load, this unique line loss factor would be
applied. To the extent that the Remote QF‟s generation did not serve local load, the standard
unscaled GMM TLF proposed by the CCC, as discussed above, would apply.

            Although SDG&E, Edison and ORA criticized the CCC‟s proposed TLF methodology for
Remote QFs serving Local Load, it is important to point out that no party disputed the formula
proposed by Mr. Beach for calculating a line loss factor that better reflects the marginal line loss
impact of Remote QF generation that serves Local Load. Instead, their criticisms were in the
nature of Mr. Linsey‟s concern that there was no QF identified that matched perfectly the
hypothetical referred to in the Workshop Report (i.e., a Remote QF whose generation matches
exactly the Local Load). ORA/Linsey, Ex. 105, at 1:11-21. As discussed above, however, the
Remote QF serving Local Load issue, and solution, applies to the extent that a Remote QF serves
a Local Load. The example of U.S. Borax, discussed both in the Workshop Report (at 21) and in
Mr. Beach‟s testimony (Ex. 17, at 18:8-17), even if it is assumed that only a portion of its
generation serves the Local Load of Edwards Air Force Base, poses a real-world issue that must
be addressed by the Commission.

            Likewise SDG&E witness Nelson‟s criticisms are not valid. Mr. Nelson argues that the
CCC‟s proposal would unjustly enrich remote QFs and send inappropriate price signals.
SDG&E/Nelson, Ex. 73, at 1:19-22. In fact, the exact opposite is true; the CCC‟s proposal is
designed to ensure that Remote QFs serving Local Load are fairly compensated and receive
accurate price signals. To the extent that a Remote QF can serve a Local Load, it should be
encouraged to do so and, in so doing, reduce system losses.

            Mr. Nelson also criticizes the CCC‟s proposal as it would need further implementation.
SDG&E/Nelson, Ex. 73, at 1:22-24. A similar criticism is levied by Edison witness Mayfield.
Edison/Mayfield, Ex. 72, at 13:22-14:13. The CCC does not dispute that the application of its

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proposed methodology will require additional efforts. The CCC does not anticipate substantial
controversy associated with this proposal. The Commission could, for example, require the
utilities to file an advice letter proposing appropriate standards. The adopted standards then
could be applied to individual QFs.

            Edison witness Mayfield had four other concerns with the CCC‟s proposal. Each may be
dismissed. Her first concern was that the CCC erroneously proposed to set the Remote QF TLF
equal to the system average GMM. Edison/Mayfield, Ex. 72, at 12:10-19. Ms. Mayfield simply
fails to understand the CCC‟s proposal. As shown in Table 2 of CCC witness Beach‟s testimony,
Exhibit 17, and as demonstrated during cross-examination of Ms. Mayfield (Tr. at 1006:27-
1007:9), the CCC does not propose to set the Remote QF TLF equal to the system average
GMM. Instead, the QF‟s “local load” TLF would be determined in accordance with the formula
presented at line 25 of page 17 of Mr. Beach‟s testimony. This formula reflects the true marginal
losses associated with the QF‟s generation, not the system average GMM.

            Second, Ms. Mayfield questions why the CCC‟s proposal wouldn‟t apply to all QFs.
Edison/Mayfield, Ex. 72, at 12:10-19. As explained by CCC witness Beach, the CCC‟s proposal
is intended to address a situation in which the ISO‟s GMM assumption deviates materially from
reality. For QF‟s located relatively close to load centers and for those that do not serve Local
Load, the ISO‟s GMM assumption is not as egregious as in the case of Remote QFs serving
Local Load. CCC/Beach, Tr. at 866:16-867:25. Thus, there is no material reason to apply the
Local Load methodology to all QFs.

            Third, Ms. Mayfield asserts that the CCC‟s proposal assumes that the relationship
between the Remote QF and the Local Load is static. Edison/Mayfield, Ex. 72, at 13:6-14. Ms.
Mayfield again is incorrect. As explained by CCC witness Beach, one could vary the Remote QF
generation and Local Load assumptions to account for real-time fluctuations; given the amount
of “data crunching” this may involve, however, the use of average data may be more appropriate.
CCC/Beach, Tr. at 860:19-861:1.

            Finally, Ms. Mayfield criticizes the U.S. Borax example, claiming that in the aggregate
there is more generation at the remote substation than there is local load. Edison/Mayfield, Ex.


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72, at 13:15-21. As discussed above, even if there is more generation than load, so long as a
significant amount of generation from a Remote QF serves a Local Load, the CCC‟s proposed
methodology is warranted. Just what constitutes a significant amount will need to be determined.

            In sum, the CCC‟s proposed methodology for determining the TLF for a Remote QF to
the extent that it serves Local Load, addresses a critical flaw with the ISO‟s GMM assumptions,
complies with PURPA and sends appropriate price signals to QF. As a result, it should be
adopted by the Commission.

III.        Conclusion.
            The CCC and Watson respectfully request that the Commission adopt the proposals set
forth above.

                                                       Respectfully submitted,


                                                       ____________________________
                                                       Joseph M. Karp
                                                       White & Case LLP
                                                       Two Embarcadero Center, Suite 650
                                                       San Francisco, CA 94111
                                                       Telephone: (415) 544-1100
                                                       Facsimile: (415) 544-0202
                                                       Attorneys for the California
                                                       Cogeneration Council and Watson
                                                       Cogeneration Company
June 1, 2000




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                                                           SUBJECT INDEX

                                                                                                                                            Page



TABLE OF AUTHORITIES ......................................................................................................... iv

SUMMARY OF RECOMMENDATIONS ................................................................................... vi

I.          Introduction. .........................................................................................................................1

II.         Discussion. ...........................................................................................................................3
            A.         Functioning Properly Criteria. .................................................................................3
                       1.         Introduction and Summary. ..........................................................................3
                       2.         The Commission should adopt the following five general standards
                                  as underlying criteria for determining whether the PX is functioning
                                  properly. .......................................................................................................5
                                  (ii)        The PX should have adequate liquidity. ..........................................7
                                  (iii)       The PX should have adequate demand responsiveness. ..................7
                                  (iv)        The PX should have transparent pricing. .........................................8
                                  (v)         There should be adequate market oversight and monitoring. ..........9
                       3.         The Commission should adopt the following five specific criteria for
                                  determining whether the PX is functioning properly. ..................................9
                                  (i)         For buyer or seller HHIs above 1,800, the Commission
                                              should require substantial evidence that such concentration
                                              does not impair the proper functioning of the PX market..............10
                                  (ii)        The ISO should have significantly raised or eliminated the
                                              current price caps in the real-time market (possibly retaining
                                              “safety net” or “damage control” price-cap authority). ..................12
                                  (iii)       The day-ahead PX and real-time ISO market prices should
                                              have averaged within 20% of each other during peak demand
                                              hours...............................................................................................14
                                  (iv)        The PX day-ahead market clearing price should be zero in no
                                              more than one percent of the hours in the immediately
                                              preceding twelve month period. .....................................................17
                                  (v)         The rate freeze must have ended. ...................................................18
            B.         SRAC Energy Pricing. ...........................................................................................19


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                   1.        Introduction and Summary.........................................................................19
                   2.        The Commission should set SRAC energy payments equal to the
                             day-ahead PX price for the zone in which the QF is located, less the
                             value of capacity in the PX price, if any, as determined in
                             accordance with Section 390(d). ................................................................22
                             (i)        The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal complies with PURPA. ...................................................23
                             (ii)       The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal complies with Section 390(c). .........................................25
                             (iii)      The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal complies with Section 390(d)..........................................25
                             (iv)       The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal is easy to implement and transparent. .............................29
                             (v)        The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal is not subject to manipulation by any party
                                        (assuming that the PX is functioning properly). ............................29
                             (vi)       The CCC/Watson, SDG&E and PG&E SRAC pricing
                                        proposal provides accurate and prospective price signals..............30
                   3.        The Commission should reject the Edison/ORA new entrant
                             proposal. .....................................................................................................30
                             (i)        The Edison and ORA new entrant proposal violates Section
                                        390(c). ............................................................................................31
                             (ii)       The Edison and ORA new entrant proposal violates Section
                                        390(d). ............................................................................................32
                             (iii)      The Edison and ORA new entrant proposal violates PURPA. ......33
                             (iv)       The Edison and ORA new entrant proposal would, if
                                        adopted, be extremely controversial and administratively
                                        burdensome. ...................................................................................36
                   4.        The Commission should reject ORA‟s heat rate cap proposal. .................38
                             (i)        The ORA heat rate cap proposal violates Section 390(d). .............38
                             (ii)       The ORA heat rate cap proposal violates PURPA. ........................39
                             (iii)      The ORA heat rate cap proposal would, if adopted, be
                                        extremely controversial and administratively burdensome. ...........41
                   5.        The Commission should reject ORA‟s proposed SRAC subtractors.........42
                   6.        The Commission should adopt the CCC‟s proposed “market basket”
                             approach to revisiting the SRAC payment methodology. ..........................43
            C.     As-Available Capacity Pricing. ..............................................................................45


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                       1.         Introduction and Summary. ........................................................................45
                       2.         While the CCC agrees that the PX price is an all-in price, it is not
                                  the only source of compensation for as-available capacity in the
                                  market. .......................................................................................................46
                       3.         The appropriate measure of as-available capacity payments for QFs
                                  in SDG&E‟s and Edison‟s service territories is the average of the
                                  prices for spinning and non-spinning reserves. ..........................................47
            D.         Line Loss Factors. ..................................................................................................49
                       1.         Introduction and Summary. ........................................................................49
                       2.         Setting the TLFs equal to the GMMs would violate PURPA and
                                  send inaccurate price signals to QFs. .........................................................50
                       3.         Setting the TLFs equal to 1.0 would be even worse than adopting the
                                  GMMs. .......................................................................................................53
                       4.         SDG&E‟s methodology for converting the results of its line loss
                                  study into TLFs improperly reduces the proposed TLFs. ..........................54
                       5.         The Commission should set the TLFs equal to unscaled GMMs
                                  (except to the extent that a Remote QF serves Local Load). .....................55
                       6.         The Commission should adopt the CCC‟s proposed TLF
                                  methodology for Remote QF generation serving Local Load. ...................56

III.        Conclusion .........................................................................................................................60




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