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					Rulemaking Nos.: 04-04-003 and 04-04-025
(U 39 M)
Exhibit No.:
Date: August 31, 2005
Witnesses: Carolyn A. Berry, Ph.D.
             Kevin F. Coffee
             Frank De Rosa
             Peter S. Fox-Penner, Ph.D.
             Harold O. La Flash
             J. Richard Lauckhart
             John S. Pappas
             Daniel D. Richard, Jr.
             Todd Strauss, Ph.D.




                 PACIFIC GAS AND ELECTRIC COMPANY

                        PREPARED TESTIMONY ON

        QUALIFYING FACILITIES POLICY AND PRICING ISSUES
                     PACIFIC GAS AND ELECTRIC COMPANY
               QUALIFYING FACILITIES POLICY AND PRICING ISSUES

                                TABLE OF CONTENTS


Chapter                          Title                             Witness          Page
          EXECUTIVE SUMMARY                                  Frank De Rosa          ES-1


  1       INTRODUCTION AND SUMMARY                           Frank De Rosa
          A. Introduction                                                           1-1
          B. Overview of Policy Context                                             1-2
          C. Proposal for Existing QFs                                              1-2
          D. Proposal for New and Expiring QFs                                      1-4


  2       POLICY
          A. Introduction                                                           2-1
          B. The Commission’s QF Program Must Change to                             2-1
             Be Consistent With the Current Electricity
             Market to Ensure Customers Pay No More Than
             Utilities’ Avoided Costs
          C. The Commission Should Require QFs Seeking                              2-3
             Long-Term Agreements to Participate in
             Competitive Solicitations
          D. Short-Term Energy Purchases Should Be Priced                           2-3
             at Market Rates


  3       PG&E PROPOSAL FOR EXISTING QF                      Carolyn A. Berry,
          CONTRACTS                                           Ph.D.
                                                             Kevin F. Coffee
                                                             Peter S. Fox-Penner,
                                                              Ph.D.
                                                             John S. Pappas
                                                             Todd Strauss, Ph.D.
          A. Outline of PG&E Pricing Proposal for Existing                          3-1
             QF Contracts (Pappas)
             1. Legal Requirements                                                  3-1
             2. Current SRAC Energy Payment                                         3-2
                Methodologies
             3. Issues From Rulemaking 99-11-022                                    3-4
             4. Overview of Proposal for SRAC Energy                                3-4
                Pricing
             5. As-Delivered Capacity Pricing                                       3-6




                                           -i-
                      PACIFIC GAS AND ELECTRIC COMPANY
                QUALIFYING FACILITIES POLICY AND PRICING ISSUES

                                  TABLE OF CONTENTS

                                       (CONTINUED)


Chapter                            Title                         Witness   Page
               6. The Commission Should Not Order A                        3-7
                   Five-Year Fixed Energy Pricing Proposal
               7. Conclusion                                               3-7
          B.   NP-15 Prices Are PG&E’s Short-Run Avoided                   3-8
               Energy Cost Because PG&E Relies on NP-15
               Prices for Dispatch Decisions (Coffee)
          C.   Assessment of PG&E’s SRAC Proposal                          3-10
               (Fox-Penner)
               1. Introduction and Purpose                                 3-10
               2. Today, PG&E’s Incremental or Short-Run                   3-13
                   Avoided Cost Is the NP-15 Day-Ahead Price
               3. Energy Prices Based on NP-15 Day-Ahead                   3-17
                   Indices Reflect Workably Competitive Prices
                   Since the Energy Crisis
               4. ICE and Dow Jones Are Appropriate                        3-19
                   Measures for the NP-15 Day-Ahead Price
                   a. ICE and Dow Jones Both Meet FERC’s                   3-19
                       Criteria on Price Indexes
                   b. There Is No Material Difference in NP-15             3-25
                       DA Prices Reported by Two Key Index
                       Providers
               5. PG&E’s Short-Term Avoided Cost for Paying                3-28
                   Energy Under the One-year Contract is the
                   NP-15 Day-Ahead Price
          D.   Proposed SRAC Energy Prices (Berry)                         3-28
               1. Comparison of Current SRAC to NP-15                      3-29
                   Prices
               2. Revisions to SRAC Formula                                3-30
          E.   Proposed Prices for As-Delivered Capacity                   3-36
               Under Existing QF Contracts and for Capacity
               Under New QF Contracts (Strauss)
               1. QF Contracts to Which the Proposed Prices                3-36
                   Would Apply
               2. PG&E’s Approach to Pricing QF Capacity                   3-37




                                            -ii-
                   PACIFIC GAS AND ELECTRIC COMPANY
             QUALIFYING FACILITIES POLICY AND PRICING ISSUES

                               TABLE OF CONTENTS

                                    (CONTINUED)


Chapter                         Title                                Witness          Page
               a. Avoided Cost for Near-Term Capacity,                                3-38
                  Including QF As-Delivered Capacity,
                  Should Not Exceed PG&E’s Cost of
                  Meeting Its RA Requirements With Near-
                  term Capacity Resource Alternatives
               b. PG&E Should Pay QFs for As-Delivered                                3-39
                  Capacity Only to the Extent the QF
                  Capacity Helps PG&E Avoid Costs of
                  Meeting RA Requirements
            3. Calculation of Proposed QF Capacity Prices                             3-40
               a. Identification of the Resource Alternative                          3-40
                  and Associated Operating Parameters
                  and Going-Forward Fixed Costs
                  (1) Resource Alternatives                                           3-41
                  (2) Operating Characteristics of                                    3-41
                      Resource Alternatives
                  (3) Going-Forward Fixed Costs of                                    3-41
                      Resource Alternatives
                  (4) Summary of Proposed Operating                                   3-43
                      Parameters and Going-Forward Fixed
                      Costs
               b. Allocation of the Annual Going-Forward                              3-43
                  Fixed Costs of the Resource Alternative
               c. Calculation of QF Capacity Payments                                 3-44
            4. Estimated QF Capacity Prices                                           3-45
            5. Conclusion                                                             3-46


  3A      APPENDIX A                                           Peter S. Fox-Penner,
                                                                Ph.D.
          ANALYSIS OF COMPETITIVE CONDITIONS IN
          CALIFORNIA ISO SPOT MARKETS


  3B      APPENDIX B                                           Carolyn A. Berry,
                                                                Ph.D.
          CALCULATION OF OVERPAYMENTS FROM                     Todd Strauss, Ph.D.
          MANDATED QF SO1 EXTENSIONS PURSUANT
          TO DECISIONS 03-12-062 AND 04-01-050




                                         -iii-
                     PACIFIC GAS AND ELECTRIC COMPANY
               QUALIFYING FACILITIES POLICY AND PRICING ISSUES

                                TABLE OF CONTENTS

                                     (CONTINUED)


Chapter                          Title                                 Witness          Page
  4       OUTLINE OF PG&E PROPOSAL                               Harold O. La Flash
                                                                 J. Richard Lauckhart
          A. Introduction (De Rosa)                                                     4-1
             1. Prices Paid Under Current Standard Offer                                4-1
                 Agreements Far Exceed PG&E’s Avoided
                 Cost
             2. The Commission Should Not Require New                                   4-5
                 Long-Term QF Power Purchase Agreements
                 Given the Provisions of the Energy Policy Act
                 of 2005 That Eliminate the PURPA Must
                 Take Obligation if a Competitive Wholesale
                 Market Exists
             3. Competitive Solicitations for Firm Power                                4-6
                 Products Are an Appropriate Means to
                 Implement PURPA in Today’s Deregulated
                 Market
             4. PG&E’s Competitive Solicitations                                        4-8
             5. PG&E Proposes to Continue Bilateral                                     4-10
                 Negotiations
             6. PG&E’s Short-Term Contract Option                                       4-10
                 a. Energy Price for Short-Term Purchases in                            4-12
                     Proposed Agreements
                 b. RA Capacity Contract Option                                         4-13
             7. PG&E’s QF Contracts Expire Gradually Over                               4-13
                 the Next 10 Years
             8. PG&E’s Proposal Furthers the Commission’s                               4-14
                 Policy Objectives
                 a. PG&E’s Proposal Reduces the Likelihood                              4-14
                     of Additional Stranded Costs From Future
                     QF Contracts
                 b. PG&E’s Proposal Supports the RPS                                    4-15
                     Program
                 c. PG&E’s Proposal Furthers Least Cost –                               4-15
                     Best Fit Procurement
                 d. PG&E’s Proposal Supports Resource                                   4-16
                     Adequacy Standards
          B. Implementation of PURPA in Other States                                    4-16




                                           -iv-
                       PACIFIC GAS AND ELECTRIC COMPANY
                 QUALIFYING FACILITIES POLICY AND PRICING ISSUES

                                  TABLE OF CONTENTS

                                       (CONTINUED)


  Chapter                          Title                               Witness           Page
                (Lauckhart)
                1. Introduction and Summary                                              4-16
                2. Research Regarding Other States’                                      4-17
                   Implementation of PURPA
                   a. Overview                                                           4-17
                   b. States Using Solicitations to Determine                            4-18
                       Avoided Cost Rates
                   c. FERC Decisions Regarding QF                                        4-20
                       Solicitations
                       (1) Texas                                                         4-22
                       (2) New York                                                      4-24
                       (3) Louisiana                                                     4-25
                       (4) Florida                                                       4-28
                       (5) Washington                                                    4-29
                   d. States Using Published or                                          4-31
                       Administratively Determined Avoided
                       Cost Rates
                   e. States That Determine Avoided Costs on                             4-32
                       a Contract-By-Contract Basis
                3. Conclusions and Observations                                          4-32
             C. Load and Resources (La Flash)                                            4-33
                1. PG&E’s Long-Term Plan                                                 4-33
                2. Re-Contracting Options                                                4-35


APPENDIX C   STATEMENT OF QUALIFICATIONS                        Carolyn A. Berry,
                                                                 Ph.D.
                                                                Kevin F. Coffee
                                                                Frank De Rosa
                                                                Peter S. Fox-Penner,
                                                                 Ph.D.
                                                                Harold O. La Flash
                                                                J. Richard Lauckhart
                                                                John S. Pappas
                                                                Daniel D. Richard, Jr.
                                                                Todd Strauss, Ph.D.




                                            -v-
             PACIFIC GAS AND ELECTRIC COMPANY
                  PREPARED TESTIMONY ON
       QUALIFYING FACILITIES POLICY AND PRICING ISSUES
                     EXECUTIVE SUMMARY

    California’s implementation of the Public Utility Regulatory Policies Act (PURPA)
is in need of a major overhaul. The nascent qualifying facility (QF) industry that the
California Public Utilities Commission (CPUC or Commission) fostered through its
implementation of PURPA in the 1980s is now mature. The Commission’s current
QF policies and pricing methodologies are no longer suited to today’s market
conditions. The recent PURPA amendments in the Energy Policy Act of 2005 reflect
the national consensus that policy reform is needed and that market-based rather
than administratively determined avoided costs are the preferred alternative.
    Pacific Gas and Electric Company’s (PG&E or the Company) QF payments are
far above its avoided cost and put significant upward pressure on rates. Short-run
avoided cost (SRAC) energy prices are approximately 30 percent above prices in
the North of Path 15 day ahead (NP-15 DA) wholesale power market. These high
SRAC energy prices are in addition to the capacity payments QFs receive pursuant
to the standard offer agreements. The above-market firm capacity prices in the
Standard Offer 2 (SO2) and Interim Standard Offer 4 (ISO4) contracts result in an
all-in price under those agreements that far exceeds PURPA’s avoided cost cap.
    In 2004, PG&E spent about $1.5 billion for QF power, roughly $380 million of
which was above the cost of alternative sources for power available in the wholesale
market. The above-market payment problem will be significantly worse by summer
2006 unless the Commission issues a decision in this proceeding to modify PG&E’s
transition formula. Currently more than 80 percent of QF energy that would
otherwise be paid according to PG&E’s monthly SRAC price is paid a negotiated
fixed price of 5.37 cents per kilowatt-hour (kWh). The negotiated fixed payment
period will expire in mid-2006 and at that time almost all QFs will be paid the SRAC
price established in this proceeding. There is a critical need for the Commission to
re-calibrate the SRAC methodology for existing contracts.


    The Commission must also move away from administratively-determined pricing
methodologies and unlimited purchase obligations when crafting policy for new and


                                         ES-1
expiring QF contracts. The Commission should take no action that will result in
additional above-market payments to QFs, particularly given the present
uncertainties introduced by the Energy Policy Act of 2005 regarding whether the
utilities will continue to be required to enter into new QF power purchase
agreements.
    PG&E recommends the Commission take the following key steps to both reform
contracting practices for new and expiring QFs, and revise PG&E’s SRAC energy
and as-delivered capacity pricing for existing QFs:
•   Update the “factor” in the SRAC energy formula so that SRAC energy prices for
    existing QFs approximate NP-15 day-ahead prices;

•   Revise the Commission’s method for calculating as-delivered capacity payments
    so that they reflect the short-run capacity costs that PG&E avoids by procuring
    short-term power from QFs;

•   Abandon the antiquated structure and pricing methods associated with standard-
    offer contracts for new QF contracts for existing projects or new projects;

•   Require QFs seeking new long-term power purchase agreements to participate
    in competitive solicitations or conduct bilateral negotiations; and

•   Adopt a one-year, market-based Edison Electric Institute (EEI) contract for new
    and expiring QFs without long-term agreements. Energy payments made by
    PG&E under this one-year contract should be based on transparent market
    indices for DA sales at NP-15.

    These proposals will modernize the Commission’s implementation of PURPA
and reduce the level of above-market payments to existing QFs. The Commission
should act now to overhaul California’s implementation of PURPA to benefit
customers and move towards market-based pricing for QFs.




                                         ES-2
PACIFIC GAS AND ELECTRIC COMPANY

           CHAPTER 1

   INTRODUCTION AND SUMMARY
                             PACIFIC GAS AND ELECTRIC COMPANY
                                         CHAPTER 1
                                INTRODUCTION AND SUMMARY

                                            TABLE OF CONTENTS

A. Introduction........................................................................................................ 1-1

B. Overview of Policy Context................................................................................ 1-2

C. Proposal for Existing QFs .................................................................................. 1-2

D. Proposal for New and Expiring QFs .................................................................. 1-4




                                                           1-i
 1                    PACIFIC GAS AND ELECTRIC COMPANY
 2                                CHAPTER 1
 3                       INTRODUCTION AND SUMMARY


 4   A. Introduction
 5          Pacific Gas and Electric Company (PG&E or the Company) requests the
 6      California Public Utilities Commission (CPUC or Commission) to revise and
 7      modernize its qualifying facility (QF) policy to market-based pricing and terms,
 8      where possible, so that it will be consistent with changes in the wholesale power
 9      market and the QF portfolio will be properly integrated in the utilities’
10      procurement plans. PG&E proposes to modify, within the current statutory
11      constraints, the short-run avoided cost (SRAC) pricing formula used to calculate
12      energy and as-delivered capacity payments to qualifying facilities (QFs) under
13      existing contracts. PG&E’s testimony also offers a comprehensive set of options
14      for new and expiring QFs to participate in PG&E’s future electric procurement
15      activities.
16          For QFs under existing contracts, PG&E proposes to comply with the
17      requirements of Section 390 (b) of the Public Utilities Code by recalibrating a
18      defined factor used to calculate its SRAC energy price so that PG&E’s SRAC
19      energy price correlates as closely as possible to the relevant market prices that
20      best represent PG&E’s avoided costs for short-term energy purchases. In
21      addition, PG&E proposes a new as-delivered capacity price that reflects its cost
22      of meeting the Commission’s resource adequacy requirements with QF
23      as-delivered power.
24          For new QFs and QFs with expiring contracts PG&E proposes three ways to
25      obtain power purchase agreements (PPA) with PG&E. The first is participation
26      in one of PG&E’s all-source or renewable (if eligible) competitive solicitations.
27      The second is bilateral contract negotiations. For both of these options, the
28      complete set of pricing and terms would be established in the final negotiated
29      PPA.
30          For QFs who do not secure a PPA though the first two routes and do not sell
31      to other wholesale buyers, PG&E proposes one-year as-delivered and firm
32      capacity contracts, with energy prices based on the market clearing price for



                                               1-1
 1         transactions in the spot wholesale market, and as-delivered capacity payments
 2         that reflect PG&E’s resource adequacy capacity costs.[1]
 3             PG&E’s proposals are fully consistent with the Commission’s all-source
 4         bidding guidelines established in Decisions 04-01-050 and 04-12-048, meet the
 5         Energy Action Plan’s (EAP) underlying goal of requiring QFs to become market
 6         participants and suggest reasonable, market-based rates for QF deliveries. The
 7         proposals comply with federal and state legislation, and are consistent with
 8         Federal Energy Regulatory Commission (FERC) rules and decisions regarding
 9         the PURPA purchase requirement.

10   B. Overview of Policy Context
11             In Chapter 2, Daniel D. Richard, Jr., PG&E’s Senior Vice President of Public
12         Policy and Governmental Affairs, explains why the current market situation calls
13         for reform of the Commission’s QF policies, suggests guiding principles for the
14         reforms, and discusses how PG&E’s proposals meet those principles.

15   C. Proposal for Existing QFs
16             Chapter 3 provides PG&E’s detailed proposal and supporting analyses for
17         reform of SRAC pricing paid to QFs under existing contracts.
18             In Section A, John Pappas, PG&E’s Manager of QF Contracts, explains the
19         existing policies, legal requirements, and payment structure for QFs under
20         existing contracts with PG&E. Mr. Pappas explains the urgent need to reform
21         SRAC prices. Although SRAC prices are 30 percent above comparable market
22         prices, customers have been somewhat protected because approximately
23         80 percent of QFs are paid SRAC energy at a fixed rate of $53.70/MWh
24         pursuant to negotiated agreements signed in the summer of 2001. However, the
25         fixed SRAC period for these QFs will expire by next summer and over
26         90 percent of QF energy will be paid according to the SRAC price set by this
27         Commission each month.
28             The SRAC energy price is calculated using a statutory formula and a factor
29         that correlates gas price changes to the SRAC energy price in the formula. As
30         the Commission has previously recognized, it has the authority and to modify the



     [1]     As explained further in Chapter 3, the North of Path 15 day-ahead (NP-15
             DA) market price is PG&E’s wholesale spot price and best represents
             PG&E’s short-run avoided energy cost.

                                                1-2
 1   factor and must modify it if it will result in a more accurate SRAC. PG&E
 2   proposes to recalibrate its factor so that SRAC energy prices correlate to NP-15
 3   DA prices.
 4       Mr. Pappas also explains that PG&E’s standard offer agreements allow the
 5   Commission to establish a SRAC methodology based on PG&E’s actual avoided
 6   cost. The QFs’ proposal to forecast the utilities’ avoided costs for five years
 7   instead of establishing SRAC is inconsistent with the standard offer contracts
 8   and therefore cannot be adopted.
 9       In Section B, Kevin Coffee, PG&E’s Manager of Power Trading, testifies
10   about PG&E’s actual short-term procurement activities and demonstrates that
11   the wholesale power market, and in particular, the NP-15 DA market, is PG&E’s
12   short-run avoided cost and guides PG&E’s dispatch decisions.
13       In Section C, Peter Fox-Penner, Ph.D., Chairman and Principal of the Brattle
14   Group, provides his expert assessment of PG&E’s SRAC for energy payments
15   to QFs. Dr. Fox-Penner explains that PG&E’s short-run avoided or incremental
16   cost is the NP-15 DA price and that the NP-15 DA market is workably
17   competitive. Appendix A to Chapter 3 provides extensive quantitative analyses
18   supporting this competitiveness assessment. Dr. Fox-Penner also confirms that
19   the price indices that PG&E proposes using in its proposed one-year
20   agreements, Dow Jones and Intercontinental Exchange (ICE), are appropriate
21   measures of the NP-15 DA price.
22       In Section D, economist Carolyn Berry, Ph.D. uses econometric analysis to
23   calculate new factors to use in the PG&E’s SRAC methodology to produce
24   SRAC energy prices that best reflect NP-15 DA prices. To maintain the current
25   SRAC structure, Dr. Berry provides a revised factor for both winter and summer.
26   The econometric analysis relies on gas prices and NP-15 DA prices from
27   2002-2003 to derive the revised factors.
28       In Section E, Todd Strauss, Ph.D., PG&E’s Director of Market Assessment
29   and Quantitative Analysis, details PG&E’s as-delivered capacity proposal.
30   Dr. Strauss first outlines the basis for payment of as-delivered capacity, and then
31   introduces the proposed method for calculating the avoided capacity payments.
32       Appendix B to Chapter 3 includes a summary of energy and capacity
33   overpayments that PG&E has made to QFs whose contracts were extended at
34   Standard Offer 1 prices by Decisions 03-12-062 and 04-01-050. PG&E provides


                                           1-3
 1         this analysis to establish the amount of refund that the QFs should be required
 2         to return to utility ratepayers pursuant to a recent decision of the California Court
 3         of Appeal.[2]

 4   D. Proposal for New and Expiring QFs
 5             For new and expiring QFs, PG&E offers a comprehensive set of options to
 6         participate in PG&E’s future electric procurement activities at market-based
 7         prices, terms, and conditions. Chapter 4 provides PG&E’s proposed policy for
 8         providing opportunities for new QFs and existing QFs with expiring contracts, to
 9         sell power to PG&E.
10             In Section A, Frank De Rosa, PG&E’s Director of Power Contracts, reviews
11         the effects of the Commission’s current policy, highlighting how QF contracts
12         have led to unfavorable payment and contract terms when compared to
13         alternatives available in the market. Mr. De Rosa discusses PG&E’s proposed,
14         market-oriented contracting opportunities: competitive solicitations, bilateral
15         negotiations, and one-year contracts based on market index prices. This set of
16         options provides reasonable prices for customers, fair opportunities to QFs, and
17         supports Commission energy policies. QF contracts will be expiring gradually,
18         thus providing an opportunity for a smooth transition to the proposed market-
19         based QF policy.
20             In Section B, Richard Lauckhart, Partner at Global Energy, provides a
21         survey of how other states, including the key QF states, have moved towards
22         competitive bidding and bilateral negotiation at market prices and terms to
23         implement the PURPA purchase obligation, and that few states require any
24         administratively-determined payments. Mr. Lauckhart’s testimony illustrates that
25         California’s PURPA policy is out of step with the rest of the country, and
26         provides an in depth review of recent PURPA policy in four key states – Texas,
27         New York, Louisiana, and Florida – as well as in the state of Washington, where
28         he was personally involved in developing reformed PURPA implementation
29         policies.
30             In Section C, Harold O. La Flash, PG&E’s Director of Integrated Planning,
31         discusses how PG&E has included QFs in its long-term procurement plan.



     [2]     Southern Cal. Edison Co. v. Public Utilities Comm., 128 Cal. App. 4th 1
             (2005).

                                                 1-4
1   Mr. La Flash explains PG&E’s current long-term competitive solicitation and the
2   special accommodations PG&E has made to give existing QFs an opportunity to
3   participate.




                                        1-5
PACIFIC GAS AND ELECTRIC COMPANY

           CHAPTER 2

            POLICY
                             PACIFIC GAS AND ELECTRIC COMPANY
                                         CHAPTER 2
                                           POLICY

                                            TABLE OF CONTENTS

A. Introduction........................................................................................................ 2-1

B. The Commission’s QF Program Must Change to Be Consistent With the
   Current Electricity Market to Ensure Customers Pay No More Than
   Utilities’ Avoided Costs ...................................................................................... 2-1

C. The Commission Should Require QFs Seeking Long-Term Agreements to
   Participate in Competitive Solicitations .............................................................. 2-3

D. Short-Term Energy Purchases Should Be Priced at Market Rates ................... 2-3




                                                           2-i
 1                   PACIFIC GAS AND ELECTRIC COMPANY
 2                               CHAPTER 2
 3                                 POLICY


 4   A. Introduction
 5          Since its implementation of Public Utility Regulatory Policies Act (PURPA),
 6      the California Public Utilities Commission (CPUC or Commission) has rarely
 7      updated or performed a comprehensive examination of the policies governing
 8      California utilities’ purchase of energy and capacity from Qualifying Facilities
 9      (QF). Today, the nascent QF industry that the Commission fostered when it first
10      implemented PURPA is a mature and significant segment of California’s
11      electricity market. The electricity market, after learning the hard lessons of the
12      recent energy crisis, is now workably competitive and is the market on which
13      PG&E relies today to supply its customers’ energy needs.
14          In this proceeding, the Commission should adopt QF policies that reflect
15      today’s wholesale electricity market. The proposals discussed in PG&E’s
16      testimony are intended to place QFs on a level playing field with other market
17      participants, so the QFs have a buyer for their power at reasonable rates that do
18      not exceed PG&E’s avoided costs for QF power.

19   B. The Commission’s QF Program Must Change to Be Consistent
20      With the Current Electricity Market to Ensure Customers Pay No
21      More Than Utilities’ Avoided Costs
22          Congress enacted PURPA in 1978 to reduce the nation’s dependence on
23      fossil fuels by encouraging the development of alternative electric generation
24      resources. The structure and regulation of the electric utility industry in 1978
25      was very different from what exists today. Twenty-five years ago, the basic
26      model of the electricity market was the vertically integrated utility, responsible for
27      building and operating power plants, building and operating the transmission
28      system to move power to load centers, and meeting the needs of its customers.
29      In northern California, aside from a few pockets of municipal utilities and a few
30      cogeneration projects, PG&E had a more or less assured customer base and
31      produced most of the power its customers consumed.
32          The power industry in California has obviously changed since that time, and
33      the Commission’s QF program must be re-examined and updated to reflect

                                               2-1
 1   today’s market structure and operations. Today, PG&E owns far fewer
 2   generation resources than it did before the advent of PURPA. For long-term
 3   planning purposes, PG&E follows the loading order established by the Energy
 4   Action Plan to acquire energy efficiency and demand response resources and
 5   renewables pursuant to the Renewable Portfolio Standard (RPS) legislation. It
 6   acquires most of the rest of its needs from wholesale power purchases, from
 7   QFs pursuant to PURPA, from the California Department of Water
 8   Resources (DWR) which in turn acquires its power from independent energy
 9   producers, and from a portfolio of bilateral contracts based on the Commission-
10   approved short-term and long-term procurement plans.
11       To meet its short-term needs, PG&E purchases power in the day-ahead and
12   real-time markets for sales in its service territory. Long-term purchases are
13   made pursuant to a competitive transparent procurement process, with PG&E’s
14   Procurement Review Group involved in each step.
15       Other changes in the wholesale electricity market have materially changed
16   PG&E’s role in procuring and delivering energy to its customers. These
17   modifications have created opportunities for QFs to market their power far
18   beyond the options that were available in 1978.
19       PG&E’s transmission system is now operated under the open access rules
20   established pursuant to Federal Energy Regulatory Commission’s (FERC)
21   Order 888. The transmission system is also administered by the California
22   Independent System Operator (CAISO) under FERC-approved tariffs.
23       PG&E does not have a monopoly on procurement services. Many of
24   PG&E’s distribution customers generate their own power through cogeneration
25   and distributed generation, or acquire it pursuant to contracts with energy
26   service providers. Others are now considering Community Choice Aggregation.
27       In 1978, the developer or operator of a cogeneration project often had
28   limited potential buyers for its output. Today, PG&E is only one of a number of
29   potential buyers. The CAISO provides transmission access on a non-
30   discriminatory basis to potential buyers throughout the West. PG&E is offering a
31   number of options for QFs to continue to contract with PG&E after their current
32   contracts expire. However, the QFs who do not choose to contract with PG&E
33   can access the Western wholesale market and achieve the best price for their
34   power under a variety of terms and conditions.


                                          2-2
 1          The Commission’s original implementation of PURPA assumed QFs
 2      supplanted the traditional utility roles in generation and construction of new
 3      facilities. That is no longer a valid assumption today. There is no reason for the
 4      Commission to continue to implement PURPA using a now-outdated model with
 5      standard offer contracts and some form of administratively determined short-run
 6      avoided cost (SRAC) formula for any new QF projects or for any existing QF
 7      projects whose contracts have expired. In fact, encouraging the QFs with their
 8      fully-amortized projects to participate in the market will further enhance the
 9      liquidity and stability of the wholesale market.

10   C. The Commission Should Require QFs Seeking Long-Term
11      Agreements to Participate in Competitive Solicitations
12          PG&E now acquires long-term capacity and energy through all-source and
13      renewable solicitations. Now that a competitive electricity market has
14      developed, QFs that desire long-term firm capacity contracts should be required
15      to participate in these solicitations to obtain new contracts. The price of a
16      winning bidder in the solicitations will establish PG&E’s avoided cost. If a QF
17      that participates in a solicitation does not win because its bid was too high, then
18      the price bid by the QF clearly exceeded PG&E’s avoided costs.
19          Competitive solicitations provide benefits to customers through improved
20      price, term, and quantities of power. Such solicitations are much better than
21      long-term standard offers and administrative means to establish avoided costs
22      and contract terms because the prices will equal PG&E’s current avoided cost
23      and the contract terms will require the seller to deliver power when PG&E’s
24      customers need it the most.
25          Long-term solicitations are also preferable to standard offer agreements
26      because they enable the utility to plan the amount of power it will purchase. If
27      long-term contracts are awarded on an as-needed basis through competitive
28      solicitations, ratepayers will be required to purchase only the power they need,
29      which avoids the over-subscription problem of the ISO4 and SO2. Also, the risk
30      of unreasonably low prices, leading to shortages of supply, should be averted.

31   D. Short-Term Energy Purchases Should Be Priced at Market Rates
32          As discussed in Chapter 3, the Commission should recognize that, in the
33      near term, California utilities purchase power in the spot market to meet their net



                                              2-3
 1   short positions. PG&E’s SRAC for energy deliveries under standard offer
 2   agreements or under new agreements should no longer exceed the price of
 3   comparable power products in the wholesale market.
 4       The Commission must revise its SRAC pricing policies to make sure that
 5   PG&E’s customers are paying a fair and reasonable price for QF power that
 6   does not exceed the market price of comparable power products. It is time to
 7   move past the artificial constructs of the 1980s, such as the QFs “In/Out”
 8   methodology. Treating the QFs as a monolithic block that may disappear
 9   overnight ignores reality and is inconsistent with the long-term stability and
10   diversity of their operations.
11       QFs should not be treated differently from other participants in the western
12   wholesale market to the detriment and expense of PG&E’s customers. PG&E
13   presents specific proposals on QF pricing in Chapters 3 and 4 and encourages
14   the Commission to adopt these proposals. Given the development of the
15   wholesale energy market, it is time to move to market-based rates and contract
16   terms for QFs.




                                           2-4
   PACIFIC GAS AND ELECTRIC COMPANY

              CHAPTER 3

PG&E PROPOSAL FOR EXISTING QF CONTRACTS
                       PACIFIC GAS AND ELECTRIC COMPANY
                                   CHAPTER 3
                    PG&E PROPOSAL FOR EXISTING QF CONTRACTS

                                          TABLE OF CONTENTS

A. Outline of PG&E Pricing Proposal for Existing QF Contracts (Pappas)............. 3-1

    1. Legal Requirements ..................................................................................... 3-1

    2. Current SRAC Energy Payment Methodologies........................................... 3-2

    3. Issues From Rulemaking 99-11-022 ............................................................ 3-4

    4. Overview of Proposal for SRAC Energy Pricing........................................... 3-4

    5. As-Delivered Capacity Pricing...................................................................... 3-6

    6. The Commission Should Not Order the Renewal of the Five-Year Fixed
       Energy Pricing Proposal............................................................................... 3-7

    7. Conclusion ................................................................................................... 3-7

B. NP-15 Prices Are PG&E’s Short-Run Avoided Energy Cost Because
   PG&E Relies on NP-15 Prices for Dispatch Decisions (Coffee) ........................ 3-8

C. Assessment of PG&E’s SRAC Proposal (Fox-Penner) ................................... 3-10

    1. Introduction and Purpose ........................................................................... 3-10

    2. Today, PG&E’s Incremental or Short-Run Avoided Cost Is the NP-15
       Day-Ahead Price ........................................................................................ 3-13

    3. Energy Prices Based on NP-15 Day-Ahead Indices Reflect Workably
       Competitive Prices Since the Energy Crisis ............................................... 3-17

    4. ICE and Dow Jones Are Appropriate Measures for the NP-15
       Day-Ahead Price ........................................................................................ 3-19

        a. ICE and Dow Jones Both Meet FERC’s Criteria on Price Indexes ....... 3-19

        b. There Is No Material Difference in NP-15 DA Prices Reported by
           Two Key Index Providers ...................................................................... 3-25

    5. PG&E’s Short-Term Avoided Cost for Paying Energy Under the One-
       year Contract is the NP-15 Day-Ahead Price ............................................. 3-28

D. Proposed SRAC Energy Prices (Berry) ........................................................... 3-28

    1. Comparison of Current SRAC Energy to NP-15 Prices.............................. 3-29




                                                          3-i
                      PACIFIC GAS AND ELECTRIC COMPANY
                                  CHAPTER 3
                   PG&E PROPOSAL FOR EXISTING QF CONTRACTS

                                         TABLE OF CONTENTS

                                               (CONTINUED)

   2. Revisions to SRAC Formula....................................................................... 3-30

E. Proposed Prices for As-Delivered Capacity Under Existing QF Contracts
   and for Capacity Under New QF Contracts (Strauss)...................................... 3-36

   1. QF Contracts to Which the Proposed Prices Would Apply......................... 3-37

   2. PG&E’s Approach to Pricing QF Capacity.................................................. 3-37

       a. Avoided Cost for Near-Term Capacity, Including QF As-Delivered
          Capacity, Should Not Exceed PG&E’s Cost of Meeting Its RA
          Requirements With Near-term Capacity Resource Alternatives ........... 3-38

       b. PG&E Should Pay QFs for As-Delivered Capacity Only to the
          Extent the QF Capacity Helps PG&E Avoid Costs of Meeting RA
          Requirements ....................................................................................... 3-39

   3. Calculation of Proposed QF Capacity Prices ............................................. 3-40

       a. Identification of the Resource Alternative and Associated Operating
          Parameters and Going-Forward Fixed Costs........................................ 3-40

            (1) Resource Alternatives ..................................................................... 3-41

            (2) Operating Characteristics of Resource Alternatives ........................ 3-41

            (3) Going-Forward Fixed Costs of Resource Alternatives..................... 3-41

            (4) Summary of Proposed Operating Parameters and Going-
                Forward Fixed Costs ....................................................................... 3-43

       b. Allocation of the Annual Going-Forward Fixed Costs of the
          Resource Alternative............................................................................. 3-43

       c. Calculation of QF Capacity Payments .................................................. 3-44

   4. Estimated QF Capacity Prices ................................................................... 3-45

   5. Conclusion ................................................................................................. 3-46




                                                        3-ii
 1                  PACIFIC GAS AND ELECTRIC COMPANY
 2                              CHAPTER 3
 3               PG&E PROPOSAL FOR EXISTING QF CONTRACTS


 4   A. Outline of PG&E Pricing Proposal for Existing QF Contracts
 5      (Pappas)
 6             It is essential to update Pacific Gas and Electric Company’s (PG&E or the
 7         Company) short-run avoided cost (SRAC) pricing methodology because PG&E
 8         has overpaid for SRAC energy for a significant period under existing standard
 9         offer contracts. PG&E’s SRAC energy prices were approximately 30 percent
10         above PG&E’s avoided costs from 2002 through 2004.[1] The additional
11         capacity payments the qualifying facilities (QFs) receive increases the disparity
12         between market prices and QF rates. These massive overpayments violate
13         Public Utility Regulatory Policies Act of 1978 (PURPA) and unfairly prejudice
14         PG&E’s customers who bear the cost of the QF power. To reduce PG&E’s
15         SRAC energy price to a price that better reflects PG&E’s actual avoided costs,
16         PG&E proposes to update the factors in the transition formula originally adopted
17         in Decision 96-12-028 and modified in Decision 01-03-067 in compliance with
18         PURPA and Section Public Utilities Code Section 390.

19         1. Legal Requirements
20                 To comply with PURPA, PG&E’s all-in price under the standard offer
21             agreements, including its energy and capacity payments, must not yield a
22             total payment that exceeds PG&E’s avoided cost for similar power products.
23             Payments to QFs that exceed PG&E’s avoided costs are neither just nor
24             reasonable and therefore violate PURPA. As demonstrated throughout this
25             chapter, the SRAC energy price formula currently yields prices that are
26             above PG&E’s avoided cost for short-term energy purchases. PG&E
27             proposes to remedy this situation by modifying factors in the transition
28             formula.
29                 Section 390(b) requires SRAC energy prices to be based on a formula
30             that reflects a starting energy price adjusted monthly to reflect changes in a



     [1]     Testimony of Dr. Carolyn Berry, Section D.1.

                                                3-1
 1            starting gas index price in relation to an average of current California natural
 2            gas border price indices. The statute requires the starting energy price to be
 3            based on 12-month averages of recent, pre-January 1, 1996 SRAC prices
 4            paid by each utility. This “transition formula” was intended to be in place
 5            only until the independent Power Exchange (PX) was “functioning properly
 6            for the purposes of determining the short-run avoided cost energy payments
 7            to be made to non-utility power generators…”[2]
 8                As described in more detail in the testimony of Dr. Carolyn Berry, the
 9            transition formula includes gas “factors” that reflects the relationship
10            between the historical border gas and SRAC prices. The California Public
11            Utilities Commission (CPUC or Commission) initially derived the factors from
12            a regression analysis.[3] The Commission has previously confirmed that it
13            has authority to modify a utility’s transition formula factor to arrive at a price
14            that better reflects a utility’s avoided cost and complies with PURPA.
15            Four years after originally adopting a factor in Southern California Edison’s
16            (SCE) transition formula, the Commission modified the factor, at SCE’s
17            request, to lower SCE’s SRAC prices.[4] QF groups petitioned for review of
18            Decision 01-03-067, claiming that revising SCE’s factor violated
19            Section 390(b). The California Court of Appeal affirmed the Commission’s
20            decision to adjust the SCE’s transition formula factor to comply with
21            PURPA’s avoided cost cap.[5] The Court of Appeal expressly rejected the
22            QFs’ contentions that the Commission lacked authority to revise the factor to
23            adjust to changes in the market.

24         2. Current SRAC Energy Payment Methodologies
25                The CPUC adopted PG&E’s transition formula in 1996 (D.96-12-028).
26            PG&E used 24-month averages of pre-January 1, 1996 prices (i.e., monthly
27            prices for calendar years 1994 and 1995) to calculate its starting energy
28            price. The starting energy price PG&E has used since 1996 continues to be


     [2]     Public Utilities Code § 390 (b).
     [3]     Decision 96-12-028, p. 14. For PG&E, the CPUC adopted two factors,
             one for summer, one for winter.
     [4]     Decision 01-03-067, p. 11.
     [5]     Southern California Edison v. Pub. Util. Comm’n, 101 Cal. App. 4th 982,
             992-93 (2002).

                                                 3-2
 1          based on the 24-month average of PG&E’s SRAC energy prices during
 2          1994 and 1995. The transition formula originally employed factors that
 3          represented a regression based on the relationship between SRAC energy
 4          price during the pre-1996 time period and California border natural gas
 5          prices during that same time period. The CPUC-adopted factors for PG&E
 6          (one for Summer Period A and one for Winter Period B) have been used
 7          since 1996 to derive PG&E’s monthly energy SRAC prices and have never
 8          been modified.
 9              PG&E has two broad categories of QF Power Purchase Agreements
10          (PPAs). The first includes Standard Offer 2 (SO2) and Interim Standard
11          Offer 4 (ISO4) PPAs. These SO2 and ISO4 PPAs typically require PG&E to
12          pay for energy at SRAC prices and for capacity at fixed prices (although
13          some QFs selected to provide as-delivered capacity in the ISO4 at SRAC
14          prices authorized from time to time by the CPUC). The second category
15          includes Standard Offer 1 (SO1) and Standard Offer 3 (SO3) PPAs. The
16          SO1 and SO3 PPAs require payment for energy at SRAC prices and for as-
17          delivered capacity at prices authorized from time to time by the CPUC. Any
18          changes to the SRAC energy pricing methodology will affect the SRAC
19          energy prices in all applicable PPAs. The firm capacity and forecasted as-
20          delivered capacity prices in SO2 and ISO4 PPAs will not be modified in this
21          proceeding.
22              Approximately 187 QFs totaling 3,200 megawatts (MW) and comprising
23          approximately 80 percent of current annual QF deliveries are paid fixed
24          energy prices averaging 5.37 cents/kilowatt-hour (kWh) in accordance with
25          five-year fixed SRAC energy price amendments, which the CPUC
26          authorized the utilities to enter into with QFs in 2001.[6] The fixed price
27          amendments expire in July and August 2006. Therefore any modification to
28          the existing transition formula will take effect after the current fixed energy
29          price amendments expire. By the end of summer 2006, over 90 percent of
30          PG&E’s QFs will be paid SRAC energy prices. Thus, it is urgent that the
31          Commission establish a transition formula that reflects PG&E’s true avoided




     [6]   D.01-06-015.

                                              3-3
 1            costs no later than July 2006 to avoid exposing PG&E’s customers to further
 2            SRAC energy overpayments.

 3         3. Issues From Rulemaking 99-11-022
 4                In June 2001, the CPUC held evidentiary hearings to address the
 5            Incremental Energy Rate and the Operations and Maintenance expense
 6            elements of the SRAC energy formula SCE used. Although the CPUC did
 7            not issue a decision on that phase of the proceeding, the need to update the
 8            SRAC methodology became apparent then.
 9                On January 21, 2005, a Joint Administrative Law Judge (ALJ) ruling
10            transferred SRAC pricing issues from Rulemaking 99-11-022 to this
11            proceeding, Rulemaking 04-04-025. PG&E’s testimony does not explicitly
12            address the issue of a separate incremental energy rate or operation and
13            maintenance expense adder because these components are subsumed in
14            the North of Path 15 day-ahead (NP-15 DA) price used to derive PG&E’s
15            proposed new SRAC energy price.

16         4. Overview of Proposal for SRAC Energy Pricing
17                As explained by Dr. Fox-Penner and by Mr. Coffee, NP-15 DA prices
18            should be deemed PG&E’s avoided cost for short-term energy purchases
19            under the standard offer agreements.[7] As shown in Dr. Berry’s testimony,
20            PG&E’s SRAC energy prices exceeded NP-15 DA market prices by
21            approximately 30 percent in the 2002-2004 period. The transition formula
22            yields prices that substantially exceed the NP-15 DA prices and does not
23            result in just and reasonable rates for QF power.
24                To remedy this problem, PG&E urges the Commission to modify the
25            Section 390(b) factors so that the 8-year “transition” formula yields SRAC
26            energy prices that are equivalent to PG&E’s avoided costs as measured by
27            transaction prices for sales at NP-15. The Commission has the authority to
28            change the “factors” in Section 390(b) to produce a price that complies with
29            PURPA. PG&E proposes to use the new factors in the transition formula
30            beginning with the first SRAC energy price posting after the Commission
31            issues its decision on this issue.



     [7]     See Sections B and C.

                                                   3-4
 1               Under PG&E’s proposal, the starting energy and border gas prices used
 2          in the formula remain unchanged.[8] The transition formula factors would
 3          be modified, however, to yield energy prices that reflect PG&E’s avoided
 4          costs. PG&E proposes to derive its new factor based on the correlation
 5          between NP-15 DA prices and border gas prices instead of the original
 6          correlation between pre-1996 SRAC energy prices and border gas prices.
 7          This adjustment to the factors will more closely align SRAC energy prices
 8          with PG&E’s actual avoided costs. PG&E proposes to use NP-15 DA prices
 9          to recalibrate its factors because, as the testimony of Dr. Fox-Penner
10          explains, SRAC energy prices should be no greater than the NP-15 DA
11          prices to comply with PURPA’s avoided cost cap. As Dr. Berry shows, if the
12          factors had been in place from 2002 through 2004, PG&E’s SRAC energy
13          prices would have closely followed NP-15 DA prices.[ 9] To ensure that the
14          proposed new factors yield SRAC energy prices which closely track actual
15          NP-15 DA prices, PG&E proposes that the Commission establish a process
16          to periodically compare SRAC energy prices with corresponding NP-15 DA
17          prices to determine if there is a correlation between those prices. This
18          process should include procedures to update the factors as necessary to
19          keep the SRAC energy prices consistent with actual NP-15 DA prices,
20          consistent with the methodology PG&E is now proposing.
21              PG&E’s proposal uses a 50/50 average of the Malin and SoCal Topock
22          gas indices to derive the historical border gas prices for the SRAC formula
23          and to calculate the new regression factors correlating border gas prices
24          with NP-15 DA prices. In Decision 01-03-067, the CPUC replaced the
25          Topock index in the formula with Malin plus transportation costs due to
26          evidence that the manipulation of the Topock index was resulting in prices
27          that were not robust. Based on current Federal Energy Regulatory
28          Commission (FERC) criteria for availability and market activity, PG&E
29          proposes that Topock be reinstated as a robust market index. Under
30          PG&E’s proposal a 50/50 average of Malin and SoCal Topock gas indices


     [8]   Section 390(b) mandates the use of the starting energy and border gas
           prices. These starting values were derived using a 24-month average of
           pre-January 1, 1996 values as originally adopted in Decision 96-12-028.
     [9]   See Figure 3-4 in Section D.

                                             3-5
 1             would be used in the transition formula along with the new factors to
 2             calculate SRAC energy prices going forward beginning with the first SRAC
 3             energy price posting after the Commission issues its decision on this issue.
 4                 Since PG&E’s proposal is based on the transition formula and only
 5             updates the factors, the resulting Time-of-Use (TOU) factors within each
 6             season will remain the same. However, since the summer and winter
 7             factors will be changed to reflect the correlation between border gas prices
 8             and NP-15 DA prices, the seasonal distribution between summer and winter
 9             will be consistent with NP-15 seasonal price patterns.
10                 PG&E proposes to establish line losses by using the Generator Meter
11             Multiplier (GMM) for each QF. In Decision 01-01-007, the CPUC adopted a
12             GMM-based formula for the transmission loss factor used in calculating QF
13             payments. According to this decision, until QFs were paid a PX-based
14             energy price, the GMM applicable to QF payments would be adjusted to
15             reflect the relative line loss of the QF power; specifically the transmission
16             loss factor would be equal to the GMM of the QF divided by the system
17             average GMM (GMMQF/GMMSYS). QFs that were paid a PX-based
18             energy price would have an unadjusted GMM applied to their payments.
19                 Consistent with PG&E’s proposal to establish a market-based formula
20             for SRAC energy prices, PG&E proposes that the transmission losses for all
21             QFs be set at their respective GMM level without dividing the GMM by the
22             system average GMM. This is consistent with the way any generator selling
23             power in the NP-15 market would be paid (i.e., the generator would be paid
24             the NP-15 price times the applicable hourly GMM).

25          5. As-Delivered Capacity Pricing
26                 The methodology for near-term[10] or as-delivered capacity payments
27             to PG&E QFs was last updated in Decision 89-06-048 and yields a price of
28             $66.43/kilowatt (kW)-yr. The methodology is based on the product of an old
29             estimate of the full fixed cost of a new combustion turbine and an Energy
30             Reliability Index (ERI) that represents an outdated assessment of PG&E’s
31             need for reliability. PG&E proposes to replace this outdated methodology




     [10]     Testimony of Dr. Todd Strauss, Section E.

                                                 3-6
 1      with one that more accurately reflects the cost of the capacity resource that
 2      PG&E avoids when procuring near-term capacity from QFs.
 3          PG&E’s proposal for a new market-based as-delivered capacity pricing
 4      methodology is presented in Section E and is sponsored by Dr. Strauss.

 5   6. The Commission Should Not Order the Renewal of the Five-Year
 6      Fixed Energy Pricing Proposal
 7          The QFs have requested the Commission to order the utilities to pay a
 8      5-year fixed price to interested QFs instead of a SRAC energy price that
 9      varies each month. Because the Commission has no authority to forecast
10      SRAC prices for five years under the standard offer agreements, the request
11      should be denied.
12          PG&E’s standard offer contracts require the Commission to establish a
13      “full short-run avoided operating cost.” A 5-year fixed price is not a short-run
14      price; it is a long-run price. If the Commission were to order a long-run price
15      for QFs operating under existing standard offer agreements, it would in
16      effect be modifying a term of those agreements, which the Commission has
17      no authority to do. Independent Energy Producers Ass’n, Inc. v. CPUC, 36
18      F.3d 848 (9th Cir. 1994). In Decision 01-06-015, the Commission approved
19      of 5-year fixed prices in lieu of posted SRAC for interested QFs, but it
20      merely authorized and did not mandate that utilities enter into the fixed-price
21      agreements. While PG&E is not adverse to negotiating such an
22      arrangement with interested QFs at a reasonable price, the Commission
23      may not impose a fixed price under standard offer agreements requiring
24      PG&E to pay its SRAC.

25   7. Conclusion
26          PG&E’s proposal to update its transition formula factors to reflect current
27      avoided costs is consistent with both PURPA and Section 390(b), and
28      results in prices that are just and reasonable for PG&E’s customers. The
29      Commission should adopt PG&E’s proposed factors so that PG&E’s SRAC
30      no longer exceeds its true avoided costs.




                                          3-7
 1   B. NP-15 Prices Are PG&E’s Short-Run Avoided Energy Cost
 2      Because PG&E Relies on NP-15 Prices for Dispatch Decisions
 3      (Coffee)
 4              PG&E meets its daily electric load obligations at the lowest possible cost to
 5          PG&E customers. The CPUC Standard of Conduct (SOC) 4 was adopted in
 6          Decision 02-10-062 and modified in Decisions 02-12-069, 02-12-074, 03-06-076
 7          and 05-01-054. SOC 4 requires PG&E to dispatch its portfolio of existing
 8          resources,[11] allocated California Department of Water Resources (CDWR)
 9          contracts, and new purchases to meet its electric load obligations in a least-cost
10          manner. Decision 04-07-028 requires system reliability and deliverability of
11          power to be included as part of least-cost dispatch.
12              PG&E has fully integrated its generation and contract resources and
13          demand-side programs with the allocated CDWR contracts when managing its
14          electric supply portfolio. These aggregated resources are considered along with
15          market opportunities for energy purchases and sales in the least-cost dispatch
16          process.
17              PG&E dispatches resources or purchases energy with the lowest
18          incremental cost of providing energy, which includes the variable operating cost
19          of its own resources or resources under its control and the market cost of
20          generation. Least-cost dispatch effectively delivers power to PG&E’s customers
21          at the lowest possible cost.
22              One way to illustrate least-cost dispatch is to stack a portfolio of resource
23          alternatives in order of cost, from least expensive to most expensive. Resources
24          are dispatched or called upon to deliver energy until the resource supply is equal
25          to forecast load and delivery obligations. A primary input into the least-cost
26          dispatch decision is the market price. The market provides a source to displace
27          more expensive resources in the portfolio stack when PG&E is short and also
28          allows less expensive resources to be sold when PG&E is long. In northern
29          California, that price is reflected by transactions at NP-15.
30              Figure 3-1 below illustrates the least-cost dispatch concept.




     [11]     PG&E’s “existing resources” include PG&E’s Diablo Canyon Nuclear Power
              Plant (DCNPP), hydro system, two remaining fossil plants (Hunters’ Point and
              Humboldt and its supply contracts with QFs and others).

                                                  3-8
 1                                          FIGURE 3-1
 2                              PACIFIC GAS AND ELECTRIC COMPANY
 3                            ILLUSTRATIVE HOURLY RESOURCE STACK



                                          12000


                                          10000
                                                               $85
                                                               $76
                                           8000                $55
                                                               $48



                                     MW
                                           6000                $46
                                                               $42
                                                               $38
                                           4000
                                                               $25
                                                               $0
                                           2000


                                              0
                                                   Hourly
                                                  Resource
                                                   Stack



 4              The resources are stacked from least expensive to most expensive. The
 5          first block of energy is 2,500 MW at a variable cost of $0/megawatt-hour (MWh).
 6          This indicates that the resource is a “must-take” and the buyer will schedule the
 7          energy onto the grid. Note that while the cost listed for the must-take resources
 8          in this simple example is $0/MWh, that cost does not represent the actual cost of
 9          those resources. The cost is represented here as $0/MWh simply because
10          there is no cost-based dispatch decision to be made due to the nature of the
11          resource or terms and conditions of the contracts.[ 12] The next block is
12          1,200 MW of dispatchable energy at $25/MWh. The third block is 1,500 MW at
13          $38/MWh. The blocks continue until the resource stack is exhausted at
14          10,000 MW with the highest variable cost at $85/MWh.
15              When load and delivery obligations are 6,000 MW, resources are dispatched
16          through the fourth block. That fourth block’s variable price is $42/MWh. If the



     [12]     For example, the vast majority of PG&E’s QF contracts are California
              Independent System Operator (CAISO) “must take” resources for which
              PG&E is barred from making economic dispatch decisions.

                                                  3-9
 1     market price is less than $42/MWh, then that block of energy will not be
 2     dispatched, instead it will be replaced with purchases from the market. Similarly
 3     if the market price were less than $38/MWh, the third block would also be
 4     replaced by market purchases. When the market price is greater than
 5     $42/MWh, then the resources will be dispatched through the fourth block and the
 6     excess above 6,000 MW will be sold to the market.
 7         If the load were 6,000 MW and the market price for the given hour were
 8     $50/MWh, then the remaining resources with a marginal cost of $46/MWh that
 9     were not being used to meet load, and the resources with a marginal cost of
10     $48/MWh, would be sold into the market.
11         Thus, existing resources in PG&E’s portfolio (i.e., utility retained generation,
12     CDWR, and those contractual obligations which allow economic dispatch) are
13     regularly compared to the market price, with power being either bought or sold at
14     that price. Regardless of the resource stack, the utility’s avoided cost for a given
15     hour becomes the market price.
16         The market price that PG&E uses to determine what resources are
17     dispatched in northern California is the NP-15 price. If the dispatch decision is
18     made day-ahead, then the price is the day-ahead NP-15 price. If the dispatch
19     decision is made hour-ahead, then the price is the hour-ahead NP-15 price.
20     PG&E’s traders are active in the market and are keenly aware of current prices
21     at which sellers are offering, buyers are bidding and the price at which the most
22     recent transaction was executed. Price discovery is available through voice
23     brokers, electronic trading platforms, such as the Intercontinental Exchange
24     (ICE), and direct contact with trading counterparties.

25   C. Assessment of PG&E’s SRAC Proposal (Fox-Penner)
26     1. Introduction and Purpose
27             PG&E requested me to evaluate PG&E’s proposal to revise the factors
28         currently used in the “Transition Formula” for determining SRAC energy
29         payments in accordance with Section 390(b). The revision would affect all
30         QF contracts that use SRAC energy pricing. The proposed changes in
31         pricing that will affect the ongoing QF contracts are described in detail above
32         in Mr. Pappas’s testimony, Section A.




                                            3-10
 1               I first note that the discussion in this chapter is devoted entirely to the
 2           provision of short-run energy products by QFs to PG&E. I include within that
 3           set of products the energy provided under existing contracts that require a
 4           price equal to PG&E’s full short run avoided operating costs as approved by
 5           the CPUC. The following types of standard offer contracts have such
 6           provisions for SRAC energy pricing: SO1 (Article 3); SO2 (Article 3(b));
 7           SO3 (Article 3); and ISO4 (Article 4, last sentence, covering the duration of
 8           the contracts after any initial fixed price period).
 9               I primarily discuss the energy value of the QF product supplied. In
10           discussing short-run energy products, I also lay out the basis for discussing
11           payments to QFs that choose to supply short-term energy under PG&E’s
12           proposed interim One-Year contracts, which are discussed by Mr. De Rosa
13           in Chapter 4. In this chapter, I do not examine payments under new
14           contracts with QFs that provide long-term firm capacity and energy to PG&E,
15           which is deferred to Mr. De Rosa’s discussion in Chapter 4, nor do I
16           examine issues of as-delivered capacity payments, which are addressed by
17           Dr. Strauss in Chapter 3, Section E.
18               For the past several years, PG&E’s “incremental” or “avoided” cost of
19           energy, as defined by PURPA, for the short-run energy products of QFs is
20           best represented by the NP-15 spot market prices.[13] As discussed in
21           more detail below, PURPA defines avoided cost as the cost of energy PG&E
22           could purchase of a like, or most similar, kind, (i.e., similar in terms of the
23           pre-notification of quantity, firmness, duration of obligation, etc.) as the QF
24           provides. (The term “Short Run Avoided Cost,” or SRAC, although it
25           predates the spot market, correctly identifies the duration attributed to the
26           product.) In Sub-section 2 below, I explain why the Day-Ahead (DA) market
27           is the appropriate spot market upon which to base avoided cost energy
28           prices.[14]



     [13]   PURPA itself refers to “incremental costs” (See PURPA Section 210,
            16 U.S.C. 824a-3(b) and (d)). The FERC regulations implementing PURPA
            use the term “avoided costs.” (See 18 C.F.R. Section 292.101(b)(6).)
     [14]   The Day-Ahead spot market and particularly the practical meaning of
            “day-ahead” is discussed in more detail below in Appendix A of my testimony.
            For exposition, I will use “Day-Ahead” and related statements like “based on
            plans made the day ahead” without continually qualifying the usage.

                                                3-11
 1               As discussed by Dr. Berry in Section D, the NP-15 DA prices have been
 2           significantly lower than the prices generated by the current Transition
 3           Formula for SRAC energy payments. Thus, PG&E has, for several years,
 4           paid prices for energy far in excess of its incremental or avoided cost,
 5           contrary to PURPA, which mandates that rates for purchases of energy by
 6           electric utilities shall not exceed “the incremental cost to the electric utility of
 7           alternative electric energy.”[15]
 8               To remedy this apparent violation of PURPA, PG&E proposes to change
 9           the factors in the current Transition Formula such that the Formula will yield
10           an SRAC energy price close to the NP-15 DA price, PG&E’s “incremental” or
11           “avoided” short-run cost of energy today. I support PG&E’s proposal to
12           revise the Transition Formula factors because the revision will result in an
13           SRAC energy price closer to PG&E’s true short-term incremental or avoided
14           cost, and therefore comply with PURPA.
15               PG&E’s proposal to revise the Transition Formula factors in the SRAC
16           formula that implements Public Utilities Code Section 390(b) is an element
17           of what should be the Commission’s overarching policy: QFs should be paid
18           based on accurate avoided costs. When purchases from a market represent
19           the true avoided cost, avoided costs should equal market prices.
20               In support of this policy, and to assess whether the NP-15 DA price is
21           the product of a workably competitive market, I analyzed prices in the NP-15
22           DA market and other nearby Western Electricity Coordinating Council
23           (WECC) DA market hubs during the January 2002 through July 2005 time
24           period.[16] I conclude that the NP-15 market has been the center of a
25           workably competitive market. I discuss the results of my analysis in
26           Sub-section 3 below, and in Appendix A to this chapter.
27               PG&E’s proposal to revise the Transition Formula factors is based on
28           Dr. Berry’s comparison of the current Transition Formula to NP-15 DA
29           prices, and her statistical estimation of new factors for that Formula. (See
30           Chapter 3, Section D below.) As the data for her analysis, Dr. Berry used


     [15]   16 U.S.C.§ 824a-3(b).
     [16]   In the following, I will often refer to my forty-three (43) month study period,
            January 2002 through July 2005, as simply “2002 – 2005,” but the precise
            duration is always understood.

                                                3-12
 1             the NP-15 DA price index produced by the ICE. In Sub-section 4 below, I
 2             explain why the ICE index price is an accurate, appropriate measure of the
 3             NP-15 DA price under standards established by FERC. I further show that
 4             ICE and another prominent index provider, the Dow Jones Company (Dow
 5             Jones), provide daily NP-15 DA prices that are extremely close in value and
 6             nearly perfectly correlated over time; and I show that Dow Jones meets the
 7             FERC standards for price indices. I thus develop the support for PG&E’s
 8             proposal to use the daily average of the ICE and Dow Jones index prices as
 9             the basis for paying for energy under PG&E’s proposed short-term one-year
10             contract, discussed in detail in Chapter 4.[17]
11                 Finally, in sub-section 5, I evaluate PG&E’s new proposal for energy
12             payments under the one-year contract for QFs whose contracts have
13             expired or are new QFs. PG&E’s proposal, as discussed by Mr. De Rosa in
14             Chapter 4, Section A, is for future contract energy payments to be based on
15             the daily NP-15 DA prices for on-peak and off-peak products. Payments
16             would be made for the amounts of energy supplied on a daily basis by the
17             QF during the on-peak and off-peak periods, respectively. The daily price
18             would be the average of the daily NP-15 DA index values produced by ICE
19             and Dow Jones, for on-peak or for off-peak energy. I have concluded that
20             the NP-15 DA price, represented by the indices of ICE and Dow Jones,
21             accurately reflects PG&E’s short-run avoided cost. An average of ICE and
22             Dow Jones DA indices is the appropriate short-term energy price to pay for
23             energy in the one-year contract.

24          2. Today, PG&E’s Incremental or Short-Run Avoided Cost Is the
25             NP-15 Day-Ahead Price
26                 The pricing of electric energy that utilities must purchase from QFs is
27             governed primarily by Section 210 of PURPA. Among other things, the
28             statute directed FERC to prescribe rules requiring electric utilities to
29             purchase energy from qualifying cogeneration facilities and qualifying small


     [17]     The one-year contract is for QFs to consider after their current contracts
              expire or for new QFs, in addition to considering PG&E’s solicitation of bids
              from these QFs in its long-term and other all-source competitive
              procurements. These options are discussed in detail in Chapter 4, but my
              discussion of the role of NP-15 Day-Ahead prices for the one-year contract is
              in this Section B.5 of Chapter 3.

                                                  3-13
 1           power production facilities (16 U.S.C. 824a-3(a)). In specifying the
 2           requirements for such rules, Section 210 provides that:
 3               No such rule prescribed under subsection (a) shall provide for a rate
 4               which exceeds the incremental cost to the electric utility of alternative
 5               electric energy (16 U.S.C. 824a-3(b)).

 6               Section 210 also sets forth the following definition:
 7               (d) Definition. – For purposes of this section, the term “incremental cost
 8               of alternative electric energy” means, with respect to electric energy
 9               purchased from a qualifying cogenerator or qualifying small power
10               producer, the cost to the electric utility of the electric energy which, but
11               for the purchase from such cogenerator or small power producer, such
12               utility would generate or purchase from another source
13               (16 U.S.C. 824a-3(d)).

14               The DA spot market is both an obvious and conservative (i.e., erring on
15           the side of overpayment) measure of PG&E’s true short-run avoided costs.
16           PURPA’s definition of avoided cost clearly and correctly envisions that
17           utilities may satisfy their short-run incremental energy needs either through
18           spot purchases or by increasing generation under their control.
19               First, since the divestiture of most of its fossil plants around 1998, PG&E
20           has been a net buyer of power, meaning that the main sources of additional
21           power in both the long and short run have been purchases, not self-owned
22           generation. For short-run spot market purchases in NP-15, there are three
23           common product types: bilateral DA, bilateral Hour-Ahead (HA) and the real
24           time imbalance energy from the market run by the CAISO.[18] While the
25           markets for these products are linked to a substantial degree by the
26           arbitrage activities of participants, the attributes of these products do differ
27           and market prices do differ from day to day.[19]
28               The DA market is more visible, more liquid and the obvious choice
29           among the three spot markets. Below I will discuss the reasons why the DA




     [18]   With the introduction of Phase 2 of the MRTU, the CAISO will centrally
            operate a Day-Ahead market. See CAISO website, “The Basics: MRTU,”
            February 22, 2005.
     [19]   As discussed by Mr. Coffee, PG&E uses the Day-Ahead spot market to
            balance its supply and demand based on all the information known one day
            ahead of delivery, and then moves on to Hour-Ahead transactions for a final
            cost minimization. Unpredictable random perturbations and real-time events
            are handled by PG&E in the CAISO imbalance energy market.

                                               3-14
 1           market, rather than the other two smaller markets, best represents PG&E’s
 2           short-run avoided cost for energy.
 3               First, as Mr. Coffee explains (Section B above), the Commission has
 4           directed PG&E to dispatch its portfolio of resources in the short-term in the
 5           least cost manner. To accomplish this, PG&E continually monitors the
 6           NP-15 DA and HA hub prices and optimizes use of all of the dispatchable
 7           resources in its portfolio in relation to the market price. Least cost dispatch
 8           is a requirement of this Commission.
 9               To implement least-cost dispatch while the DA market is open, PG&E
10           deliberately refrains from running its own generators to produce amounts of
11           additional power at any time whenever its cost of buying spot power from
12           the NP-15 DA market is less than its cheapest available generator. Instead,
13           PG&E will supply all incremental energy needs by purchasing from the DA
14           market. This “production policy” is not merely chosen by PG&E, it is also a
15           requirement of this Commission, as discussed by Mr. Coffee. Thus, the
16           Commission’s own rules ensure that the actual incremental cost to procure
17           added short-term energy for PG&E is never more than the NP-15 DA
18           price.[20]
19               Because the NP-15 hub is the marketplace from which PG&E obtains its
20           incremental energy needs, NP-15 DA prices represent PG&E’s short-run
21           avoided costs within the meaning of PURPA. In the Sub-section 3, I discuss
22           my conclusion that the NP-15 DA price is also the product of a workably
23           competitive market.[21]
24               PURPA also requires that the non-price attributes be considered when
25           determining the avoided cost paid to QFs. From this standpoint, the product
26           traded on DA spot market is as valuable, or more valuable, than short-run


     [20]   Similarly, under Commission approved policies PG&E makes sales in the DA
            market when its cost of production from its own generators is less than the
            DA market price. These times, PG&E’s incremental cost of generating
            energy starts below the DA market price and moves toward it through Least
            Cost Dispatch. Paying QFs DA market prices at all times therefore overstates
            PG&E’s true short-run avoided costs during some hours, but the difference is
            probably not large.
     [21]   The NP-15 market is the appropriate geographic market even if PG&E might
            make some transactions in other geographic markets like SP-15 and pay
            transmission charges. Purchases from these other geographic markets are
            effectively linked to the NP-15 markets through arbitrage opportunities.

                                              3-15
 1           energy provided by standard offer QFs. This is because DA traded energy
 2           is “financially firm” energy scheduled one day in advance. For SO1 and
 3           SO3 QFs, there is no advance notice of energy availability, making the
 4           energy less valuable than traded DA energy. QFs selling under SO2 and
 5           ISO4 contracts have availability requirements that must be met in order to
 6           receive significant capacity payments, but these QFs are not obligated to
 7           schedule at all, deliver power in any given hour, or give dispatch notices. No
 8           PG&E QFs selling under standard offer contracts pays liquidated damages
 9           for the non-delivery of power in any given hour, although liquidated damages
10           is a standard feature of significant value to PG&E and other buyers in the
11           NP-15 spot market. As a result, NP-15 DA prices are an overpayment for
12           standard offer QF energy when non-price factors are taken into account.
13               The CAISO real time market is now used only as “last resort” for
14           unpredictable imbalances. Thus, market participants, including PG&E, must
15           make reasonable efforts to serve forecasted short-term (i.e., DA or HA)
16           deficiencies in the DA and HA markets.
17               The NP-15 DA price is very transparent, based on the fact that there are
18           at least three different providers of an NP-15 DA index approved by FERC,
19           including the ICE and Dow Jones indexes that PG&E is using. In contrast,
20           there is only one FERC-approved provider of the NP-15 HA price index,
21           Powerdex, and that price information can be spotty.[22] Moreover, the HA
22           market by its nature breaks the power product down into non-standard
23           hourly blocks, e.g., super peak strips. This makes data collection and index
24           calculation more complicated. It is my opinion that the NP-15 HA price is
25           not as good a choice as the NP-15 DA price as the index for PG&E’s
26           short-run avoided cost.
27               Another reason why the DA index is appropriate is that the DA price is
28           the choice of power market participants use as the benchmark price for
29           settling financial and physical contracts for trading hubs across the U.S.,
30           including NP-15 energy. The DA price is frequently used to settle financial



     [22]   In its order reviewing price index providers and price indices, FERC approved
            only one provider (Powerdex) of NP-15 HA price indices. However, the
            NP-15 volumes reported by this provider are small and actual prices are often
            unavailable due to lack of transaction data.

                                              3-16
 1             contracts such as forwards and swaps. For example, the NYMEX Dow
 2             Jones NP-15 Electricity Price Index Swap Contract (on-peak) is settled by
 3             cash payment based on the contract price and the so-called “Floating Price,”
 4             which is the arithmetic average of the Dow Jones NP-15 DA on-peak price
 5             indices for the contract month.[23] The DA price is also chosen for pricing
 6             certain monthly contracts that provide physical delivery of daily financial
 7             contracts at a spot market index price.
 8                 Given the nature of the CAISO real time imbalance market and the
 9             relative disadvantages and reduced liquidity of the HA market, the NP-15 DA
10             price index is the most reasonable measure of the NP-15 spot price and a
11             reasonable, conservative measure of PG&E’s short-run avoided cost.

12          3. Energy Prices Based on NP-15 Day-Ahead Indices Reflect
13             Workably Competitive Prices Since the Energy Crisis
14                 In sub-section 2 above, I explain why the DA spot market price is, in
15             fact, PG&E’s short-run energy avoided cost (or, more accurately, an
16             overestimate of same). To verify that this marketplace is sufficiently liquid to
17             serve as an avoided cost benchmark, I have assessed the character and
18             strength of competition in the NP-15 DA power market.
19                 To explore these questions, I analyzed price levels in the NP-15 DA
20             power market, as reported by ICE from 2002 to 2005 and compared them to
21             other DA power prices delivered in related markets or trading hubs:
22             South-of-Path 15 (SP-15), the California-Oregon Border (COB), and
23             Palo Verde (PV). My analysis, presented in more detail in Appendix A,
24             concludes that the NP-15 DA hub is within a larger market that is workably
25             competitive. I find that DA prices are nearly identical across the CAISO
26             control area and also close in the other two nearby trading hubs during the
27             vast majority of all hours. Thus, NP-15 is almost always part of a larger
28             market, either SP-15, COB or PV, depending upon season. Historical prices
29             of these hubs during the 2002 to 2005 period are at levels that show that the
30             market is sufficiently robust and well-functioning. There have been few
31             “price separations” within the CAISO control area and also few price spikes



     [23]     See “New York Mercantile Exchange Inc. Online Rulebook,” Chapter 644,
              NYMEX Dow Jones NP-15 Electricity Price Index Swap Contract.

                                                3-17
 1           across the Western U.S. The CAISO’s automatic mitigation program,
 2           designed to capture and mitigate excessively high sales bids in the RT
 3           market, has not been triggered once in the last three and a half years.
 4               My conclusion that the NP-15 market is workably competitive is also
 5           supported by the CAISO evaluation of its real-time energy market. The
 6           CAISO Department of Market Analysis’s (DMA’s) 2003 Annual Report on
 7           Market Issues and Performance, states: “[a] review of market performance
 8           shows that 2003 resulted in the most competitive short-term energy market
 9           since the start of the restructured California electric market in 1998.”[24]
10               One tool the DMA uses to assess the strength of competition is the
11           residual supplier index (RSI). The CAISO’s threshold for poor competition is
12           an RSI less than 1.1, and competition grows as the RSI number rises above
13           1.1. DMA estimates that the 2002 and 2003 RSI values indicate a healthy
14           market, with suppliers pivotal in less than 1.5 percent and 0.2 percent of the
15           hours in 2002 and 2003, respectively.[25]
16               In its recent 2004 report, the DMA reported a similar conclusion
17           regarding 2004.
18               The RSI indices in 2004 were nearly as high as in 2003, which were the
19               highest of the past five years.[26] In 2004 the RSI levels were less than
20               1.1 in less than 0.55 percent of the hours (only 48 hours out of 8760). In
21               contrast, there were 3,215 hours or 37 percent of the hours in 2001
22               where the RSI was less than 1.1. These results indicate that the
23               California markets in 2004 were again significantly more competitive
24               than in 2000 and 2001 as a result of the addition of new generation ad
25               high levels of net imports over the period. The RSI levels are consistent
26               with the market outcomes and short-term energy market price-cost
27               mark-ups observed in 2004.[27]

28               As a result, I conclude that the NP-15 DA hub prices in the period from
29           2002 to 2005 are formed in a highly liquid, much larger WECC spot market
30           and have not been significantly distorted by adverse competitive conditions.



     [24]   DMA — CAISO, 2003 Annual Report of Market Issues and Performance
            (April 2004), at p. ES-1.
     [25]   Id., p. ES-12 and DMA — CAISO, 2002 Annual Report of Market Issues and
            Performance (April 2003), at p. ES-11.
     [26]   The 1.1 RSI level was chosen simply as it is close to 1.0 which would indicate
            a situation in which the potential to exercise market power is high.
     [27]   DMA — CAISO, 2004 Annual Report of Market Issues and Performance
            (April 2005), at p. ES-12.

                                             3-18
 1          4. ICE and Dow Jones Are Appropriate Measures for the NP-15
 2             Day-Ahead Price
 3                  The true NP-15 DA energy price is the volume-weighted average of the
 4             price of all standard firm DA transactions for “next day” energy in NP-15, by
 5             whatever means have been used to consummate the trade. Each day,
 6             buyers of NP-15 DA energy seek the lowest price for their purchases and
 7             sellers of NP-15 DA energy seek the highest price for their sales, so there is
 8             a high degree of communication by telephone and over the internet during
 9             the peak trading activity in the morning of each trading day. The activity of
10             these competing traders, buyers seeking lower prices and sellers seeking
11             higher prices, is the force of competition that drives the NP-15 DA price at
12             which actual transactions are made.
13                  Various organizations report NP-15 DA On-Peak and Off-Peak index
14             prices one or more days after each trading session. Prominent NP-15 DA
15             price index providers include the ICE and Dow Jones. While ICE reports
16             prices executed on its electronic trading platform, the other index providers
17             report prices based upon confidential polls of market participants. However,
18             no index provider guarantees that its indices are based upon the total NP-15
19             DA volume. As I explain below, the differences in the price reports of two
20             prominent NP-15 DA index providers, ICE and Dow Jones, are negligible.
21             Since the two indexes are produced by independent entities and use
22             different methodologies, this near identity suggests that the indices are
23             indeed close to the unobserved true price (i.e., the average price reflecting
24             every one of the DA transactions). Moreover, I show that ICE and Dow
25             Jones both meet the FERC’s standards for reliable price indices, passing the
26             critical liquidity (or market volume) criteria by a wide margin.
27             a.   ICE and Dow Jones Both Meet FERC’s Criteria on Price Indexes
28                     The development and reporting of public price indices for electric
29                  power and natural gas has been substantially scrutinized by FERC in
30                  the past several years.[28] In several dockets, FERC has set standards


     [28]     E.g., Dockets PL03-3-000, Policy Statement on Natural Gas and Electric
              Price Indices, July 2003; PL03-3-004, Report on Natural Gas and Electric
              Price Indices, May, 2004; and PL03-3-005, Order Regarding Future
              Monitoring of Voluntary Price Formation, Use of Price Indices in Jurisdictional
              Tariffs, and Closing Certain Tariff Dockets, November, 2004.

                                                 3-19
 1               for the use of a price index in its own jurisdictional tariffs. FERC’s
 2               standards cover both the processes by which index providers operate
 3               and also the minimum level of liquidity, or volume, of the trading of the
 4               energy product each market period, that the index itself must meet.
 5               There are distinct standards for daily, weekly, and monthly price indices.
 6               FERC discusses but adopts no standards for the level of availability, or
 7               completeness of data for all reported market periods.
 8                   In Order PL03-3-005, the Commission states that in terms of
 9               process: “In order for a price index to be used in a jurisdiction tariff, the
10               index must be published or provided by an index developer that has met
11               all or substantially all of the standards of Policy Statement paragraph 33,
12               and must provide the volume and number of transactions upon which
13               the index value is based, or indicate when no such data is
14               available.”[29] Using these criteria, in its November 2004 order FERC
15               approved the following providers of NP-15 indices: ICE, Dow Jones,
16               Bloomberg, Platts, Btu/Data Transmission Network, Io Energy LLC, and
17               Powerdex.[30]
18                   PG&E’s proposed revision to the SRAC Transitional Formula for
19               certain ongoing QF contracts (Berry Testimony in Section D) is based
20               on the historical, monthly averages of daily NP-15 DA prices. Moreover,
21               the PG&E proposal for an optional One-Year Backstop contract for
22               expiring and new QFs bases energy payments directly on the daily
23               NP-15 DA on-peak and off-peak prices, using an average of the ICE and
24               Dow Jones indices.
25                   For use of a daily price index in a jurisdictional tariff, FERC has set
26               the minimum acceptable liquidity criteria that must be met for a 90-day
27               review period (for example, the second quarter of 2005).[ 31] FERC
28               specifies that an index need pass only one of these criteria. The FERC
29               Liquidity Standards are:


     [29]   FERC Docket Nos. PL03-3-005, et al. Order Regarding Future Monitoring of
            Voluntary Price Formation, Use of Price Indices in Jurisdictional Tariffs, and
            Closing Certain Tariff Dockets, November 2004, p. 29.
     [30]   109 FERC ¶ 61, 184, at P 39 (Nov. 19, 2004).
     [31]   Supra at P 66. Paragraph 66 adopts the liquidity standards.

                                               3-20
 1               •   the average daily volume of trades included in the calculation of the
 2                   index must be at least 2,000 MWh; or

 3               •   the average daily number of transactions must be at least five; or

 4               •   the average daily number of counterparties must be at least five.

 5                   The ICE and the Dow Jones NP-15 on-peak and off-peak DA
 6               Indices easily meet FERC’s adopted minimum standard for liquidity.
 7               (The ICE and Dow Jones NP-15 DA indices also have high availability,
 8               for which no FERC standards were adopted.)
 9                   For ICE’s liquidity test, Table 3-1 displays average NP-15 DA values
10               for all three liquidity standards: MWh volumes, numbers of transactions,
11               and number of counterparties. ICE easily meets all three. For the index
12               of the daily on-peak power product price, ICE has over six times the
13               required MWh volume and number of transactions and over three times
14               the required number of counterparties.[32] For the Dow Jones liquidity
15               test, Table 3-2 displays the volume data on the Dow Jones NP-15 DA
16               on-peak and off-peak indices and shows that these two Dow Jones
17               indices pass the FERC MWh volume standard by over eight and three
18               times, respectively. I show only the MWh volume metric for Dow Jones,
19               because as part of its policy, Dow Jones does not collect and/or report
20               either the number of transactions or number of counterparties.




     [32]   In addition to meeting all of FERC’s required criteria for index providers and
            the specific criteria for index locations, the ICE NP-15 on-peak and off-peak
            DA price indices also satisfy several additional criteria that FERC staff
            recommended:
            First, as an exchange, ICE has direct access to verifiable trade information for
            long and short positions and therefore does not double-count transactions in
            computing its index price.
            Second, ICE produces additional index price data that FERC has advocated
            but not required, including: daily high and low prices, the number of distinct
            counterparties to transactions included in the index, and the number of
            distinct transactions included in the index.
            Furthermore, unlike the other standard indexes provided for NP-15, the ICE
            price index is currently provided at no charge on the internet from the 10x
            Group (a subsidiary of ICE). Thus, ICE NP-15 Day-Ahead index prices are
            transparent to all market participants, whether or not they actually trade
            NP-15 Day-Ahead energy.

                                              3-21
1   However, FERC only requires that an index pass one standard, and
2   Dow Jones passes the MWh volume standard easily.




                              3-22
1                                                             TABLE 3-1
2                                                PACIFIC GAS AND ELECTRIC COMPANY
3                                             ICE-DAY-AHEAD INDEX SUMMARY STATISTICS



         90-Day Review Period                                    On-Peak Averages                                                  Off-Peak Averages
                                                 Average           Average # of     Average # of                  Average             Average # of     Average # of
                                                  Daily               Daily        Counterparties                  Daily                 Daily        Counterparties
         Start             End                   Volume            Transactions     Transacting                   Volume             Transactions      Transacting
                                                  MWh                   #                #                         MWh                     #                #
                                                   [1]                 [2]              [3]                         [4]                   [5]              [6]
        Jan-02            Mar-02                        9,779                   22               15                      3,600                     13               11
        Feb-02            Apr-02                       13,832                   29               17                      3,558                     13               11
        Mar-02            May-02                       16,128                   34               18                      3,647                     13               12
        Apr-02            Jun-02                       16,099                   35               19                      3,777                     14               12
        May-02            Jul-02                       13,522                   31               19                      4,426                     16               14
        Jun-02            Aug-02                       13,569                   31               19                      5,739                     20               15
        Jul-02            Sep-02                       13,532                   31               18                      5,533                     19               14
        Aug-02            Oct-02                       14,149                   33               18                      4,873                     17               13
        Sep-02            Nov-02                       12,037                   28               16                      3,639                     13               12
        Oct-02            Dec-02                        9,844                   23               15                      3,573                     13               12
        Nov-02            Jan-03                        7,753                   19               13                      3,200                     12               11
        Dec-02            Feb-03                        7,712                   19               14                      3,060                     11               11
        Jan-03            Mar-03                        8,874                   22               15                      3,218                     12               11
        Feb-03            Apr-03                        9,468                   23               16                      3,139                     12               11
        Mar-03            May-03                       10,549                   25               17                      3,417                     13               12
        Apr-03            Jun-03                       14,010                   34               19                      3,347                     13               12
        May-03            Jul-03                       16,343                   39               20                      4,461                     16               14
        Jun-03            Aug-03                       17,481                   42               21                      4,920                     18               14
        Jul-03            Sep-03                       15,335                   37               20                      5,578                     19               15
        Aug-03            Oct-03                       13,159                   32               19                      5,113                     18               14
        Sep-03            Nov-03                       11,416                   28               17                      4,763                     16               14
        Oct-03            Dec-03                       12,036                   29               17                      4,331                     15               13
        Nov-03            Jan-04                       12,684                   30               17                      4,696                     16               13
        Dec-03            Feb-04                       12,574                   30               17                      4,558                     16               13
        Jan-04            Mar-04                       10,582                   26               16                      3,635                     14               11
        Feb-04            Apr-04                       10,509                   26               16                      3,531                     14               11
        Mar-04            May-04                       12,287                   30               17                      4,095                     15               12
        Apr-04            Jun-04                       13,226                   32               17                      4,712                     17               13
        May-04            Jul-04                       14,426                   35               17                      4,380                     16               13
        Jun-04            Aug-04                       14,056                   34               17                      4,226                     16               13
        Jul-04            Sep-04                       14,805                   36               18                      4,465                     16               13
        Aug-04            Oct-04                       13,813                   33               18                      5,142                     19               14
        Sep-04            Nov-04                       13,063                   32               19                      6,203                     22               15
        Oct-04            Dec-04                       12,847                   32               19                      6,974                     26               16
        Nov-04            Jan-05                       14,168                   35               19                      7,107                     26               16
        Dec-04            Feb-05                       14,064                   35               19                      5,827                     22               15
        Jan-05            Mar-05                       15,100                   38               20                      6,013                     23               15
        Feb-05            Apr-05                       13,818                   34               20                      6,084                     24               16
        Mar-05            May-05                       16,390                   40               21                      7,627                     28               18
        Apr-05            Jun-05                       19,008                   47               21                      8,119                     30               19
        May-05            Jul-05                       21,226                   52               23                      9,550                     34               19

         Jan-02           Jul-05                        13,361                   32                  18                    4,921                  18               14

    FERC Criteria                       [a]              2,000                   5                    5                   2,000                   5                 5


    Source:          https://www.theice.com/webreports/indices/powerForm.do

    [1] Average daily on-peak flow volume during review period.
    [2] Average number of transactions supporting each on-peak flow day price during review period.
    [3] Average number of distinct counterparties involved in transactions supporting each on-peak flow day price during review period.
    [4] Average daily off-peak flow volume during review period.
    [5] Average number of transactions supporting each off-peak flow day price during review period.
    [6] Average number of distinct counterparties involved in transactions supporting each off-peak flow day price during review period.
    [a] See FERC Order Regarding Future Monitoring of Voluntary Price Formation, Use of Price Indices in Jurisdictional
    Tariffs, and Closing Certain Tariff Dockets , November 19, 2004.




                                                                                  3-23
                                        TABLE 3-2
                           PACIFIC GAS AND ELECTRIC COMPANY
                      DOW JONES DAY-AHEAD INDEX VOLUME STATISTICS

     90-Day Review Period                          On-Peak Averages                       Off-Peak Averages
                                                              Average                                  Average
                                                               Daily                                    Daily
     Start                End                Observations     Volume                Observations       Volume
                                                  #            MWh                       #              MWh
                                                 [1]            [2]                     [3]              [4]
            Jan-02           Mar-02              76            22,172                    90                   6,921
           Feb-02            Apr-02              76            21,614                    89                    6,880
           Mar-02            May-02              78            20,730                    92                   7,528
           Apr-02            Jun-02              77            20,854                    91                    8,298
           May-02             Jul-02             77            19,389                    92                   9,028
           Jun-02            Aug-02              78            19,831                    92                   9,136
            Jul-02           Sep-02              77            21,222                    92                   8,237
           Aug-02            Oct-02              78            25,798                    92                   6,855
           Sep-02            Nov-02              76            25,792                    91                   6,426
           Oct-02            Dec-02              77            22,949                    92                   6,893
           Nov-02             Jan-03             76            17,757                    92                   6,760
           Dec-02            Feb-03              75            14,381                    90                   6,002
            Jan-03           Mar-03              76            14,278                    90                   5,423
           Feb-03            Apr-03              76            13,944                    89                   5,656
           Mar-03            May-03              78            14,867                    92                   5,698
           Apr-03            Jun-03              77            14,423                    91                   5,873
           May-03             Jul-03             77            16,050                    92                   7,835
           Jun-03            Aug-03              77            16,965                    92                   8,366
            Jul-03           Sep-03              77            17,634                    92                   8,981
           Aug-03            Oct-03              78            15,989                    92                   8,099
           Sep-03            Nov-03              76            14,976                    91                   8,563
           Oct-03            Dec-03              77            16,472                    92                   8,457
           Nov-03             Jan-04             76            18,312                    92                   9,423
           Dec-03            Feb-04              76            19,216                    91                   9,387
            Jan-04           Mar-04              77            15,335                    91                   7,371
           Feb-04            Apr-04              77            15,190                    90                   5,817
           Mar-04            May-04              78            15,393                    92                   6,217
           Apr-04            Jun-04              77            16,375                    91                   7,810
           May-04             Jul-04             77            14,272                    92                   7,584
           Jun-04            Aug-04              78            12,422                    92                   6,681
            Jul-04           Sep-04              77            12,643                    92                   5,809
           Aug-04            Oct-04              77            11,507                    92                   6,279
           Sep-04            Nov-04              76            12,198                    91                   7,933
           Oct-04            Dec-04              77            12,810                    92                   9,219
           Nov-04             Jan-05             76            16,276                    92                   10,092
           Dec-04            Feb-05              75            17,024                    90                   8,401
            Jan-05           Mar-05              76            17,596                    90                   8,132
           Feb-05            Apr-05              77            15,534                    89                   7,155
           Mar-05            May-05              78            15,912                    92                   7,725
           Apr-05            Jun-05              77            16,314                    91                   7,845
           May-05             Jul-05             76            19,893                    92                   9,344

            Jan-02            Jul-05            1100           17,361                   1308                  7,607

FERC Criteria                          [a]                     2,000                                          2,000


Sources:             NP15 DJ DA Indices 2002 2004 for R0404025reo7.xls and Dj DA NP15 2005 thru July.csv.

[1] Total number of on-peak days in review period.
[2] Average daily on-peak flow volume during review period.
[3] Total number of off-peak days in review period.
[4] Average daily off-peak flow volume during review period.

[a] FERC criteria represent minimum levels of daily average activity during a 90 day review period required
    for index prices at a specific index location to be used in a jurisdictional tariff.
 See FERC Order Regarding Future Monitoring of Voluntary Price Formation, Use of Price Indices
    in Jurisdictional Tariffs, and Closing Certain Tariff Dockets, November 19, 2004.




                                                         3-24
 1   b. There Is No Material Difference in NP-15 DA Prices Reported by
 2      Two Key Index Providers
 3          I have analyzed the daily and monthly average ICE and Dow Jones
 4      NP-15 price indices for the period from January 2002 through July 2005.
 5      Over this 43 month study period, I find that the ICE and Dow Jones
 6      NP-15 on-peak and off-peak index prices are very close in terms of their
 7      reported daily values. First, the monthly average of the NP-15 DA
 8      prices of ICE and Dow Jones are extremely close during the study
 9      period, as shown by plotting separately the on-peak and off-peak prices
10      of ICE and Dow Jones, in Figure 3-2. (Note also that the difference
11      between the monthly average prices reported by ICE and Dow Jones is
12      plotted in Figure 1 and stays very close to zero).
13          Second, the levels of daily prices for NP-15 DA products are very
14      close. Table 3-3 displays the values for several measures of the
15      difference between the on-peak and off-peak DA index prices for ICE
16      and Dow Jones. Over the entire study period, the average daily
17      difference in the independent ICE and the Dow Jones prices for on-peak
18      energy is about nine cents per MWh or 0.2 percent (2/10 of a percent).
19      The off-peak differential is seven cents per MWh, which is also
20      0.2 percent. This closeness supports the hypothesis that both of these
21      independent indices provide a reasonably accurate measure of the true
22      NP-15 DA price (calculated from all NP-15 transactions).
23          Third, the correlation coefficient between the daily price indices of
24      ICE and Dow Jones for NP-15 DA for on-peak is 0.999 and for off-peak
25      is 0.999. The correlation coefficients between the monthly averages of
26      the price indices of ICE and Dow Jones for NP-15 DA are 0.977 and
27      0.977 for on- and off-peak, respectively.




                                     3-25
1                                                                   FIGURE 3-2
2                                                       PACIFIC GAS AND ELECTRIC COMPANY
3                                                      MONTHLY AVERAGES AND DIFFERENCES
4                                                   BETWEEN DOW JONES AND ICE DA PRICE INDICES



            75


                                                                                                                                              DJ and ICE
            65
                                                                                                                                              On-Peak
                                                                                                                                              Prices

            55



            45
    $/MWh




            35



            25
                                                                                                                                                                       DJ and ICE
                                                                                                                                                                       Off-Peak
            15                                                                                                                                                         Prices


             5



            (5)
                                                                         11/1/2002




                                                                                                                                                11/1/2003




                                                                                                                                                                                                                       11/1/2004
                  1/1/2002


                             3/1/2002


                                        5/1/2002


                                                   7/1/2002


                                                              9/1/2002




                                                                                     1/1/2003


                                                                                                3/1/2003


                                                                                                           5/1/2003


                                                                                                                        7/1/2003


                                                                                                                                   9/1/2003




                                                                                                                                                            1/1/2004


                                                                                                                                                                           3/1/2004


                                                                                                                                                                                      5/1/2004


                                                                                                                                                                                                 7/1/2004


                                                                                                                                                                                                            9/1/2004




                                                                                                                                                                                                                                   1/1/2005


                                                                                                                                                                                                                                              3/1/2005
                                        Monthly Average of Daily ICE Price During On-Peak Period                                               Monthly Average of Daily DJ Price During On-Peak Period
                                        Difference Between Monthly ICE and DJ On-Peak Prices                                                   Monthly Average of Daily ICE Price During Off-Peak Period
                                        Monthly Average of Daily DJ Price During Off-Peak Period                                               Difference Between Monthly ICE and DJ Off-Peak Prices




                                                                                                                      3-26
1                                                      TABLE 3-3
2                                         PACIFIC GAS AND ELECTRIC COMPANY
3                                COMPARISON OF ICE AND DOW JONES NP-15 DA INDEX PRICES

                                                           On Peak                                                                      Off Peak
                                                                                       Percent                                                                      Percent
                             Average         Average                      StDev of    Difference           Average        Average                      StDev of    Difference
         Time                 Daily           Daily      Average Daily      Daily      Between              Daily          Daily      Average Daily      Daily      Between
        Period              ICE Price        DJ Price     Difference     Difference   Averages            ICE Price       DJ Price     Difference     Difference   Averages
                             $/MWh           $/MWh          $/MWh          $/MWh           %               $/MWh          $/MWh          $/MWh          $/MWh          %
                               [1]             [2]            [3]            [4]          [5]                [6]            [7]            [8]            [9]         [10]

           Jan-02                23.86           23.92          (0.05)         0.12          -0.2%                18.46       18.52          (0.07)         0.37         -0.4%
          Feb-02                 25.33           25.36          (0.03)         0.12          -0.1%                20.20       20.24          (0.04)         0.26         -0.2%
          Mar-02                 35.57           35.71          (0.14)         0.41          -0.4%                30.60       30.91          (0.31)         0.37         -1.0%
          Apr-02                 31.14           31.17          (0.03)         0.24          -0.1%                19.47       19.35           0.12          0.27          0.6%
          May-02                 28.94           28.88           0.06          0.16           0.2%                17.40       17.51          (0.11)         0.38         -0.6%
           Jun-02                30.38           30.50          (0.12)         0.44          -0.4%                15.30       15.29           0.02          0.40          0.1%
            Jul-02               37.14           37.20          (0.07)         0.49          -0.2%                17.35       17.27           0.07          0.28          0.4%
          Aug-02                 29.16           29.23          (0.07)         0.26          -0.2%                20.03       20.00           0.02          0.16          0.1%
          Sep-02                 34.52           34.53          (0.01)         0.24           0.0%                25.17       25.24          (0.08)         0.25         -0.3%
           Oct-02                37.26           37.34          (0.08)         0.17          -0.2%                25.21       25.34          (0.13)         0.41         -0.5%
          Nov-02                 39.99           40.51          (0.52)         0.60          -1.3%                31.16       31.58          (0.42)         0.32         -1.3%
          Dec-02                 45.50           45.79          (0.30)         0.52          -0.7%                33.97       34.13          (0.16)         0.38         -0.5%
           Jan-03                43.73           43.84          (0.11)         0.18          -0.3%                31.89       32.25          (0.36)         0.57         -1.1%
          Feb-03                 57.59           57.76          (0.17)         0.70          -0.3%                45.74       45.78          (0.04)         0.47         -0.1%
          Mar-03                 57.76           57.86          (0.10)         0.60          -0.2%                44.44       44.51          (0.07)         0.49         -0.2%
          Apr-03                 45.19           45.41          (0.22)         0.47          -0.5%                33.74       33.91          (0.16)         0.32         -0.5%
          May-03                 43.12           43.34          (0.22)         0.76          -0.5%                23.51       23.51          (0.00)         0.19          0.0%
           Jun-03                49.05           49.13          (0.08)         0.32          -0.2%                28.08       28.38          (0.31)         0.39         -1.1%
            Jul-03               55.00           55.17          (0.17)         0.33          -0.3%                41.27       41.45          (0.18)         0.67         -0.4%
          Aug-03                 50.24           50.25          (0.01)         0.22           0.0%                38.58       38.81          (0.23)         0.32         -0.6%
          Sep-03                 48.64           48.77          (0.13)         0.38          -0.3%                36.94       37.06          (0.12)         0.17         -0.3%
          Oct-03                 45.27           45.34          (0.07)         0.17          -0.1%                33.44       33.54          (0.10)         0.24         -0.3%
          Nov-03                 42.58           42.57           0.01          0.16           0.0%                34.38       34.59          (0.20)         0.29         -0.6%
          Dec-03                 49.61           49.70          (0.09)         0.44          -0.2%                38.17       38.25          (0.07)         0.22         -0.2%
           Jan-04                49.89           50.00          (0.10)         0.23          -0.2%                40.09       39.98           0.10          0.37          0.3%
          Feb-04                 46.65           46.73          (0.07)         0.38          -0.2%                39.41       39.41           0.00          0.21          0.0%
          Mar-04                 42.45           42.47          (0.01)         0.16           0.0%                34.07       33.99           0.07          0.35          0.2%
          Apr-04                 47.93           48.05          (0.12)         0.16          -0.3%                37.90       37.92          (0.02)         0.24         -0.1%
          May-04                 59.08           59.02           0.05          0.25           0.1%                43.24       43.19           0.06          0.16          0.1%
           Jun-04                54.68           54.71          (0.02)         0.32           0.0%                36.51       36.48           0.03          0.26          0.1%
            Jul-04               59.79           59.80          (0.01)         0.47           0.0%                43.95       44.00          (0.05)         0.43         -0.1%
          Aug-04                 56.73           56.77          (0.04)         0.26          -0.1%                43.09       43.10          (0.01)         0.17          0.0%
          Sep-04                 50.27           50.24           0.03          0.20           0.1%                36.45       36.55          (0.11)         0.32         -0.3%
          Oct-04                 56.63           56.79          (0.16)         0.47          -0.3%                42.12       42.02           0.10          0.33          0.2%
          Nov-04                 65.32           65.44          (0.12)         0.27          -0.2%                49.92       49.91           0.01          0.22          0.0%
          Dec-04                 64.13           64.16          (0.03)         0.16           0.0%                49.25       49.33          (0.08)         0.39         -0.2%
           Jan-05                57.10           57.22          (0.12)         0.19          -0.2%                41.60       41.57           0.04          0.25          0.1%
          Feb-05                 53.23           53.26          (0.04)         0.06          -0.1%                41.94       41.92           0.02          0.14          0.0%
          Mar-05                 56.77           56.76           0.01          0.08           0.0%                42.33       42.39          (0.07)         0.21         -0.2%
          Apr-05                 58.77           58.72           0.05          0.21           0.1%                45.06       45.11          (0.05)         0.11         -0.1%
          May-05                 51.33           51.49          (0.16)         0.35          -0.3%                30.68       30.57           0.11          0.54          0.4%
          Jun-05                 52.17           52.23          (0.05)         0.29          -0.1%                31.05       31.16          (0.11)         0.32         -0.4%
           Jul-05                73.10           73.16          (0.06)         0.37          -0.1%                44.50       44.62          (0.12)         0.39         -0.3%

       Average       [a]         47.50           47.59          (0.09)         0.31          -0.2%                34.36       34.43          (0.07)         0.32         -0.2%


    Source:          IntercontinentalExchange (ICE) and Dow Jones and Company (DJ).

    Notes:
    [1] ICE average daily NP15 day ahead on-peak price.
    [2] Dow Jones and Company average daily NP15 day ahead on-peak price.
    [3] Monthly average of daily NP15 on-peak day ahead price difference between ICE and Dow Jones.
    [4] Monthly standard deviation of daily NP15 on-peak day ahead price difference between ICE and Dow Jones.
    [5] = [3] / ([1] + [2]) x 2
    [6] ICE average daily NP15 day ahead off-peak price.
    [7] Dow Jones and Company average daily NP15 day ahead off-peak price.
    [8] Monthly average of daily NP15 off-peak day ahead price difference between ICE and Dow Jones.
    [9] Monthly standard deviation of daily NP15 off-peak day ahead price difference between ICE and Dow Jones.
    [10] = [8] / ([6] + [7]) x 2

    [a] Average of monthly values reported




4                                        My conclusion is that the use of the ICE index to develop monthly
5                               average prices to estimate the new Factors for the Transition Formula

                                                                                      3-27
 1             for SRAC energy pricing is appropriate. Moreover, PG&E’s proposal to
 2             use the average of the ICE and the Dow Jones NP-15 DA indexes
 3             combines two indices that are both reliable and is a very sound
 4             computational approach.

 5     5. PG&E’s Short-Term Avoided Cost for Paying Energy Under the
 6         One-year Contract is the NP-15 Day-Ahead Price
 7             PG&E proposes to offer a one-year contract to QFs whose contracts
 8         have expired or are new QFs. As Mr. De Rosa explains in Chapter 4, the
 9         energy payments under the one-year contracts are to be based on the daily
10         NP-15 DA on-peak and off-peak prices.
11             According to Mr. De Rosa, the design goal for the one-year contract is
12         distinct from, but complementary with, the option the QF has to bid into
13         PG&E’s long-term (or medium-term) procurements. QFs signing One-Year
14         contracts would have the option to terminate the contract if a long-term
15         PG&E contract was secured and approved by the Commission. Thus, by
16         design the kind of energy provided under the one-year contract is similar to
17         what PG&E procures outside its long-term commitments, i.e., its short-term
18         purchases. Thus, PG&E’s avoided cost from this purchase is its short-run
19         avoided cost.
20             In discussing the reasons why the NP-15 DA price was PG&E’s
21         short-term avoided cost, I mentioned the Commission’s requirement that
22         PG&E least cost dispatch protocols involving the NP-15 DA hub price as its
23         benchmark, the workable competitive nature NP-15 DA hub and western
24         spot markets generally, and the accuracy of the indices for NP-15 DA prices
25         of ICE and Dow Jones. These same facts support my conclusion that the
26         energy payments under the proposed one-year contract accurately reflect
27         PG&E’s short-run avoided cost.

28   D. Proposed SRAC Energy Prices (Berry)
29         PG&E asked me to evaluate whether Section 390(b) presently yields SRAC
30     energy prices equivalent to NP-15 DA prices. I have also assisted PG&E in
31     modifying the Section 390(b) formula by creating a new “factor” to replace the
32     existing one to yield SRAC energy prices that are close to NP-15 DA prices. As
33     data for my analysis I used the NP-15 day ahead price index reported by the



                                            3-28
 1          Intercontinental Exchange (ICE).[33] My analysis consists of two parts. First, I
 2          compare the SRAC energy prices that have resulted from the interim SRAC
 3          energy pricing formula (“Transition Formula”)[34] to NP-15 DA prices from ICE
 4          and find that these SRAC energy prices are substantially different from NP-15
 5          DA prices. Second, I derive new values for the seasonal factors embedded in
 6          the Transition Formula by running a set of regressions using NP-15 DA prices
 7          and California border index gas prices. The new values that I derive for the
 8          seasonal Factors yield SRAC energy prices that are close to NP-15 DA prices.

 9          1. Comparison of Current SRAC Energy to NP-15 Prices
10                   ICE posts daily day-ahead peak and off-peak index prices for NP-15 on
11              its web site.[ 35 ] I compared these prices to SRAC energy prices in
12              two different ways—on a daily basis and on a monthly basis.
13                  First, I averaged the daily peak and off-peak prices and compared the
14              resulting weighted average daily NP-15 DA ICE prices (“Daily NP-15 DA
15              Prices”) to posted monthly SRAC energy prices on a day-to-day basis and
16              found that SRAC prices exceeded Daily NP-15 DA Prices during
17              88.2 percent of the days between January 1, 2002 and June 30, 2005, with
18              an average price difference of 30.5 percent over this period.
19                  Next, I averaged the Daily NP-15 DA Prices by month (“Monthly NP-15
20              DA Prices”) and compared the Monthly NP-15 DA Prices to SRAC energy
21              prices, and found that SRAC energy prices exceeded Monthly NP-15 DA
22              Prices in 38 out of 42 months. The largest difference between these
23              monthly prices occurred in March 2003 when the SRAC energy price
24              exceeded the Monthly NP-15 DA Price by $43.15/MWh. In contrast, the
25              largest amount by which the Monthly NP-15 DA Price exceeded the SRAC
26              price was $3.84/MWh in October 2004. Figure 3-3 shows SRAC energy and
27              Monthly NP-15 DA Prices from January 2002 to June 2005. Overall, SRAC




     [33]     ICE is an internet based over-the-counter (OTC) trading platform. See
              Dr. Fox-Penner’s testimony in Section C.4 above for a discussion of why ICE
              provides an appropriate source of price information.
     [34]     For an explanation of the Transition Formula see Section A.2.
     [35]     See www.theice.com and look under “Price Indices.”

                                                3-29
 1             energy prices exceed Monthly NP-15 DA Prices by 30.6 percent over this
 2             period.[36]


                                         Figure 3-3
                    Comparison of SRAC Energy and Monthly NP15 DA Prices
     100.00


      90.00


      80.00


      70.00


      60.00


      50.00


      40.00


      30.00


      20.00


      10.00


       0.00
       M -04
       Ap -04




       M -05
       Ap -05
       Ap -02




       M -03
       Ap -03
       M -02




         g 3




       Ju -04


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       Ju -05
       Ju -02




       Ju -03
         g 2




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       Fe -0 4




        Ju 0 4




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            05
       Fe -0 2




        Ju 0 2




       Fe -0 3




       O -03
       Ja -02




       D -03
       Ja -03




       O -04

       D -04
       Ja -04
       O -02

       D -02




       N t-04




       M -05
       N -02




       M -03




       N -03




       M -04
       M -02




       Se -03




       Se -04
       Se -02




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          n-




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          b
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                                 Posted SRAC Energy Price          Monthly NP15 DA Price




 3                 As Dr. Fox-Penner explains, NP-15 DA Prices reflect PG&E’s short-term
 4             avoided cost for power under PURPA.[ 37 ] Thus, the Transition Formula is
 5             producing SRAC energy prices that are 30 percent greater, on average,
 6             than PG&E’s avoided costs. The next section presents a modification of the
 7             Transition Formula that yields SRAC energy prices that are closer to NP-15
 8             DA Prices.

 9          2. Revisions to SRAC Formula
10                 The Transition Formula used to derive monthly SRAC energy prices has
11             the following form:
12                 Pn = Po + Po * [(GPn - GPo)/GPo] * Factor



     [36]     This comparison does not consider the additional capacity payment QFs
              receive under existing standard offer contracts.
     [37]     See Section C.2.

                                                            3-30
 1               Where:
 2               Pn is the SRAC energy Price for the posting period (month),
 3               Po is a fixed predetermined starting energy price,
 4               GPo is a fixed predetermined starting California border gas index price,
 5               GPn is a current California border gas index price calculated for the
 6           period; and
 7               Factor is a number that reflects the relationship between historical gas
 8           prices and historical SRAC energy prices.[ 38 ]
 9              The starting energy price, the starting gas price, and the Factor in the
10           above SRAC formula vary by season for PG&E.[39] There are
11           two seasons: winter (November 1 – April 30) and summer (May 1 –
12           October 31). The parameter values for the winter season are:
13                   Po = $.023973/kWh
14                   GPo = $1.6394/Dth
15                   Factor = 0.7875


16               The parameter values for the summer season are:
17                   Po = $.018748/kWh
18                   GPo = $1.4457/Dth
19                   Factor = 0.6270
20               As shown above, the current Transition Formula is producing SRAC
21           energy prices that are substantially above PG&E’s avoided costs. However,
22           the changes that can be made to the formula must be consistent with
23           Section 390(b). In particular, the starting energy prices and starting gas
24           prices must remain fixed at their current values and the formula must retain
25           its current form such that it can be “adjusted monthly to reflect changes in a
26           starting gas index price in relation to an average of current California natural




     [38]   See Section A.2 for the history of the current SRAC Transition Formula.
     [39]   This formula omits time of use factors that are also part of the SRAC energy
            formula. PG&E does not propose any revisions to the time of use factors and
            thus I do not explain them here. (See Section A.4 above.)

                                              3-31
 1           gas border price indices,” as explained in Section 390(b).[40] Thus, I did
 2           not consider alternative starting values or functional forms of the Transition
 3           Formula.
 4               Given the restrictions on the starting gas and energy prices, and the
 5           structural form of the Transition Formula, one obvious way to correct the
 6           Transition Formula is to revise the Factors to better reflect the relationship
 7           between gas border index prices and PG&E’s avoided costs. The new
 8           Factors (“Revised Factors”) would be set in such a way that when the
 9           current natural gas border index price is put into the Transition Formula, the
10           resulting SRAC energy price will be close to the Monthly NP-15 DA Price.
11               To derive the Revised Factors, I have done a regression analysis using
12           bid-week California border gas index prices and Monthly NP-15 DA
13           Prices.[41] The Transition Formula can be rearranged into the following
14           form:
                                  Pn − Po GPn − GPo
15
                                         =          * Factor
16                                   Po     GPo
17               This functional form presumes a linear relationship between the
18           percentage change in gas prices (from the baseline starting gas price) and
19           the percentage change in energy prices (from the baseline starting energy
20           price). A linear regression using current data on percentage changes in gas
21           prices and percentage changes in energy prices will yield a slope parameter
22           that is similar to the Factor in the Transition Formula. If the linear regression
23           is restricted to go through the origin (that is, go through the point (0,0) or the
24           point with a zero y-intercept), then the resulting slope parameter can be
25           substituted directly into the Transition Formula as the Revised Factor. This



     [40]   Section 390(b) states that, “[u]ntil the requirements of subdivision (c) have
            been satisfied, short run avoided cost energy payments paid to nonutility
            power generators by an electrical corporation shall be based on a formula
            that reflects a starting energy price, adjusted monthly to reflect changes in a
            starting gas index price in relation to an average of current California natural
            gas border price indices. The starting energy price shall be based on
            12 month averages of recent, pre-January 1, 1996, short-run avoided energy
            prices paid by each public utility electrical corporation to nonutility power
            generators. The starting gas index price shall be established as an average
            of index gas prices for the same annual periods.”
     [41]   As explained in Section A.4, the border gas index price is based on a 50/50
            mix of Malin and Topock border prices.

                                               3-32
 1           permits use of more current data that reflects the relationship between
 2           changes in the California border index gas prices and Monthly NP-15 DA
 3           Prices to derive a Revised Factor using a regression analysis. Substitution
 4           of the Revised Factor into the Transition Formula will then produce SRAC
 5           energy prices that more accurately reflect PG&E’s avoided costs when
 6           current California border index gas prices are substituted in the formula.
 7           Given starting prices for gas and energy, California border gas index
 8           prices,[42] and Monthly NP-15 DA Prices for the period January 2002 to
 9           December 2003, I ran two regressions, one for each season, using the
10           above equation. The estimated regression coefficients yield Revised
11           Factors for the SRAC equation. True uncertainty in the estimated
12           regression coefficients may be larger than suggested by the standard
13           econometric tests due to the restrictions imposed on the SRAC formula by
14           Section 390 (b). Nonetheless, the estimated regression coefficients are
15           usable in a revised SRAC formula and the Revised Factors yield SRAC
16           energy prices that closely track actual Monthly NP-15 DA Prices for the
17           period January 2002 to June 2005.[43]
18               A comparison of the Revised Factors to the current Factors is shown in
19           Table 3-4.




     [42]   The gas price data used in the regressions is an average of bid week gas
            prices published in Natural Gas Intelligence and Platts Inside FERC’s Gas
            Market Review, at Malin and Topock.
     [43]   The data used in these regressions are not stationary. In non-stationary data,
            the mean is not fixed or “stationary” but changes over time. In the data used
            here, the mean is increasing. The standard errors and t-statistics from an
            ordinary least squares (OLS) regression are not valid when data is
            non-stationary. Adjustments, such as differencing the data, can be attempted
            to correct for this problem. However, these adjustments would ultimately
            necessitate changes in the form of the SRAC equation that may not be
            permissible under the constraints of Section 390 (b). Nonetheless, I have
            done some preliminary analysis using differenced data and have found that
            the some of the regression coefficients are not statistically significant. Thus
            even if these changes in the SRAC equation were authorized, my preliminary
            analysis does not indicate that the results would provide regression
            coefficients that are statistically superior (are significant at a high level) to the
            regression coefficients proposed here. Given that the methodology is the
            same and the Revised Factors that I estimated yield a far better estimate of
            avoided cost than do the original factors, the Commission should use the
            Revised Factors proposed here.

                                                3-33
                                            Table 3-4
                          Comparison of Current and Revised Factors


                       Season    Current Factor         Revised Factor
                       Winter           0.7875               0.3909

                       Summer          0.6270                0.5193



 1               The Revised Factors in Table 3-4 are based on gas and electricity
 2           prices from the 2002-2003 period. I also considered two other sets of
 3           possible Revised Factors that were based on gas and electricity prices from
 4           alternative time periods. I ran regressions to derive Revised Factors using
 5           prices from a broader 2002-2004 period and from a later 2003-2004 period.
 6           I chose among the various Revised Factors (based on different time
 7           periods) by performing tests to see which set of Revised Factors would have
 8           produced SRAC energy prices closest to Monthly NP-15 DA Prices if the
 9           Revised Factors had been in place during the January 2002 to June 2005
10           period.
11               For each set of Revised Factors, I compared the predicted SRAC
12           energy price (the SRAC energy price that would have resulted if the given
13           Revised Factor and the then current gas price were substituted into the
14           Transition Formula) to the Monthly NP-15 DA Price for each month in
15           two different periods: (a) January 2002 to December 2004; and (b)
16           January 2005 to June 2005. For each period, I took the difference between
17           the predicted SRAC energy price and the Monthly NP-15 DA Price for each
18           month, squared that difference, and then added together all squared
19           differences to obtain a “sum of squared errors.” This is one measure of how
20           close the predicted SRAC energy prices are to the Monthly NP-15 DA
21           prices.[44] The sum of the squared errors in both the January 2002 to



     [44]   Squaring the error provides a measure that treats positive and negative
            values equally and weights larger errors more heavily than smaller errors.
            The Revised Factors with the smallest sum of squared errors has the best fit
            i.e., best predicts Monthly NP-15 DA prices.

                                             3-34
 1         December 2004, and January 2005 to June 2005 periods is smallest using
 2         the Revised Factors derived from 2002-2003 data.
 3             Another way to evaluate the different sets of Revised Factors is to
 4         compare the total revenues that a QF selling 1 MWh each month would
 5         have earned in the January 2002 to June 2005 under each set of Revised
 6         Factors and compare that to the total revenues the QF would have earned if
 7         paid the Monthly NP-15 Price. This comparison is done in Table 3-5. Total
 8         revenues under the Revised Factors based on 2002-2003 data most closely
 9         match total revenues that would have been earned if the QF had been paid
10         the Monthly NP-15 DA Price.


                                           Table 3-5
                                   Comparison Of Revenues

                                              Total Revenues From           Percentage
                                             Sale of 1 MWh Each         Above Monthly
              Payment Based On
                                          Month From January 2002          NP-15 DA
                                                  to June 2005               Prices

        Monthly NP-15 DA Prices                        $1747.54

        Transition Formula with Factors
                                                       $1761.48                0.80%
     Derived from 2002-2003 Data
        Transition Formula with Factors
                                                       $1813.28                3.76%
     Derived from 2002-2004 Data
        Transition Formula with Factors
                                                       $1829.21                4.67%
     Derived from 2003-2004 Data


11             The Revised Factors contained in Table 1 produce SRAC energy prices
12         for the January 2002 to June 2005 period that closely track Monthly NP-15
13         DA Prices. Figure 3-4 graphs the predicted SRAC energy prices based on
14         Revised Factors derived from data in the 2002-2003 period and Monthly NP-
15         15 DA Prices.




                                           3-35
                                           Figure 3-4
                        Predicted SRAC Energy and Monthly NP15 DA Prices
       70.00


       60.00


       50.00


       40.00


       30.00


       20.00


       10.00


        0.00
                2




                4
                3




                5
        M 4




        M 5
        M 2




        M 3




               03

                3




               04

                4
               02

                2
        Se 2




        Se 3




              04




        Se 4




              05
              02




              03




              -0
              -0




              -0
              -0




             -0




             -0
             -0




             -0




             -0




             -0
             -0
            l-0




            l-0




            l-0
           p-




           p-




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          ar




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         Ju




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         Ju
        Ja




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        M




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                            Predicted SRAC Energy Price          Monthly NP15 DA Price




 1   E. Proposed Prices for As-Delivered Capacity Under Existing QF
 2      Contracts and for Capacity Under New QF Contracts (Strauss)
 3              This section presents PG&E’s proposed payments for as-delivered capacity
 4          under existing standard offer contracts, and for firm capacity for new QFs or QFs
 5          with expiring contracts that enter into the one-year contracts described in
 6          Chapter 4.[45] Such as-delivered capacity and one-year contract capacity is
 7          herein referred to as “near-term” capacity, because such capacity is not
 8          contractually obligated to PG&E in the long-term, but only on an as-delivered or
 9          one-year ahead horizon. The near-term capacity prices proposed here would be
10          in effect upon approval by the Commission.
11              Specifically, PG&E proposes to pay a near-term capacity price based on the
12          cost of alternative capacity resources available to PG&E in the near-term
13          procurement horizon.
14              Only QF capacity that can be counted to meet PG&E’s resource adequacy
15          (RA) requirements helps PG&E avoid costs of meeting its RA requirements.


     [45]      As explained in Chapter 4, new QFs and those with expiring contracts that do
               not sell to other wholesale buyers or do not to obtain contracts through a
               competitive solicitation or bilateral negotiation with PG&E, may sell to PG&E
               under a one-year contract at their option.

                                                          3-36
 1          Thus, only QF capacity that can be counted to meet PG&E’s RA requirements
 2          should earn a capacity payment.
 3              The remainder of this section explains how near-term capacity prices are
 4          calculated, and provides a sample calculation of the proposed near-term
 5          capacity price using actual market prices from 2004.

 6          1. QF Contracts to Which the Proposed Prices Would Apply
 7                  The near-term capacity prices PG&E proposes would apply to capacity
 8              sold to PG&E as either as-delivered capacity under existing standard offer
 9              contracts, or firm capacity under the one-year contracts.
10                  Under each existing standard offer contract, PG&E pays either firm
11              capacity or as-delivered capacity. Firm capacity prices under existing
12              long-term SO2 and ISO4 contracts are approximately $200/kW-yr, which is
13              far above the ceiling for long-term capacity price implied by the fixed cost of
14              new conventional resource alternatives. PG&E is not proposing to change
15              fixed capacity prices under existing SO2 and ISO4 contracts. However,
16              PG&E does propose to modify the price for short-run as-delivered capacity
17              under existing PPAs requiring payment for as-delivered capacity, including
18              SO1, SO3 and some ISO4 PPAs.[46] The current price for this as-delivered
19              capacity is $66.43/kW-yr, which is currently above PG&E’s cost for near-
20              term capacity implied by alternative sources of capacity available to PG&E.

21          2. PG&E’s Approach to Pricing QF Capacity
22                  PG&E’s proposal follows two basic principles. First, avoided cost for
23              near-term capacity, including QF as-delivered capacity, should not exceed
24              PG&E’s cost of meeting its RA requirements with near-term capacity
25              resource alternatives.
26                  Second, PG&E should pay QFs for as-delivered capacity only to the
27              extent the QF capacity helps PG&E avoid costs of meeting RA
28              requirements. If the QF capacity is not counted towards PG&E’s RA
29              requirements or if PG&E has no more RA capacity need, there is no avoided
30              RA cost.


     [46]     Some QFs under ISO4 contracts receive as-delivered capacity payments at
              prices authorized from time to time by the Commission, not firm payments for
              contracted capacity. Also, QFs under ISO4s receive as-delivered capacity for
              amounts delivered in excess of the firm capacity contracted amount.

                                                 3-37
 1           a.   Avoided Cost for Near-Term Capacity, Including QF As-Delivered
 2                Capacity, Should Not Exceed PG&E’s Cost of Meeting Its RA
 3                Requirements With Near-term Capacity Resource Alternatives
 4                    PG&E’s near-term capacity resource alternatives are purchases
 5                from existing resources. Ownership of or contracts with these resources
 6                provide PG&E customers with energy, capacity, and ancillary service
 7                benefits. In exchange, PG&E pays or incurs a fixed fee (that does not
 8                vary with the amount of energy and ancillary services produced by the
 9                resource), and variable fees (that do vary with the amount of energy and
10                ancillary services produced by the resource). Generally speaking, an
11                owner of an existing resource has incentive to keep a resource in
12                operation if the resource is anticipated to have total revenues at least as
13                much as its fixed and variable costs.
14                    The principle of near-term economic equilibrium suggests that, for
15                the resource alternative determining PG&E’s avoided cost of meeting
16                the RA requirement, the total revenue stream generated by the fixed
17                and variable fees from PG&E, minus the variable costs associated with
18                fuel and operations and maintenance, ought to cover the going-forward
19                fixed costs of the resource. Further, PG&E’s avoided cost of meeting its
20                RA requirement is the going-forward fixed costs of this resource
21                alternative, plus the variable costs of this resource alternative, minus the
22                variable fees from PG&E.
23                    Equivalently, if net energy benefits of this resource alternative are
24                defined as variable fees from PG&E minus variable costs, then PG&E’s
25                avoided cost of meeting the RA requirement is the going-forward fixed
26                costs of this resource alternative minus the net energy benefits of this
27                resource alternative.[47]
28                    To the extent QFs are currently paid a separate energy price, they
29                are already compensated for the energy value they provide to PG&E’s


     [47]    It is assumed in the above that this resource alternative has no revenue
            streams other than that generated by the fixed and variable fees from PG&E;
            if this resource alternative did have such revenue streams, then they would
            help meet the going-forward fixed costs of the resource alternative, and
            thereby lower the fixed fee needed from PG&E. The result would be a
            reduction in PG&E’s cost of meeting its RA requirement.

                                               3-38
 1               customers. Therefore, the QF as-delivered capacity price should reflect
 2               only the avoided cost of capacity. This avoided cost of capacity is the
 3               going-forward fixed costs of the resource alternative, minus the net
 4               energy benefits of the resource alternative.
 5                   For the proposed one-year contract, the avoided cost of capacity is
 6               the same: the going-forward fixed costs of the resource alternative,
 7               minus the net energy benefits of the resource alternative.
 8           b. PG&E Should Pay QFs for As-Delivered Capacity Only to the Extent
 9               the QF Capacity Helps PG&E Avoid Costs of Meeting RA
10               Requirements
11                   For QFs that help PG&E avoid costs in meeting the RA
12               requirements, PG&E proposes to pay the capacity price as described
13               above. PG&E also proposes to use the Commission’s adopted Phase 2
14               counting rules to determine the historical monthly amount of capacity
15               that each QF contributes to RA adequacy for the upcoming year, and
16               pay a capacity price for such monthly amounts.
17                   Decision 04-10-035 requires load serving entities (LSEs) to submit
18               compliance filings on September 30 of each year demonstrating that the
19               LSE has secured 90 percent forward commitments toward meeting the
20               15-17 percent planning reserve requirement for the following May
21               through September period.[48] LSEs are also required to secure the
22               remaining 10 percent of the planning reserve margin for each month of
23               the year, not less than one month ahead of the operating month.
24                   QF SO1 contracts enable a utility to avoid capacity costs to the
25               extent that they have demonstrated, historically, that they have qualified
26               RA capacity that reduces PG&E’s needs to make year-ahead purchases
27               (to meet 90% of its RA requirement – September 30 for the following
28               year), or month-ahead purchases for the remaining 10 percent RA
29               requirements. In Decision 04-10-035, the Commission adopted
30               counting rules for QF power that rely on the projects’ “historic
31               performance at peak” to determine their respective RA qualifying




     [48]   D.04-10-035, mimeo p. 52, Conclusion of Law No. 3 (2004).

                                              3-39
 1                  capacity.[49] Decision 04-10-035 also recognized the need to
 2                  determine the qualifying capacity of resources on a monthly basis.[50]
 3                  Additionally, Decision 04-10-035, and in particular the RA workshop
 4                  report referenced by the decision[51] recognized that because the
 5                  existing standard offer contracts are “put” contracts, historical
 6                  performance is a better measure of a QF’s qualifying capacity than
 7                  contract capacity.
 8                      Decision 04-10-035 deferred to a second phase of the RA
 9                  proceeding (Phase 2) the counting rules that would apply to QF power,
10                  and in particular for determining the qualifying capacity of wind and solar
11                  resources.[52] Phase 2 is expected to be completed later this year with
12                  the issuance of a new RA decision.

13          3. Calculation of Proposed QF Capacity Prices
14                  In this section, PG&E describes how the proposed QF capacity prices
15             will be calculated. The steps involved in this calculation are:
16             (a) identification of the resource alternative and its associated operating
17             parameters and going-forward fixed costs; (b) monthly allocation of the
18             annual going-forward fixed costs of the resource alternative; and
19             (c) calculation of PG&E’s cost of securing RA from the resource alternative.
20             a.   Identification of the Resource Alternative and Associated Operating
21                  Parameters and Going-Forward Fixed Costs
22                      PG&E’s capacity resource alternatives are existing resources with
23                  which PG&E might contract. Based on an analysis prepared by the
24                  staffs of the California Energy Commission (CEC), the CPUC, and
25                  CAISO,[53] northern California has adequate reserves without adding
26                  new resources through 2009 under the 1-in-2 forecast peak load
27                  standard adopted by the Commission, and through 2007 under a more


     [49]     D.04-10-035, supra at p. 54, Conclusion of Law No. 16.
     [50]     Id. at p. 24.
     [51]     Administrative Law Judge Michelle Cooke, Workshop Report on Resource
              Adequacy Issues, June 15, 2004.
     [52]     D.04-10-035, supra at p. 47.
     [53]     Presentation by the state agencies’ staff before the Senate Energy Utilities
              and Communications Committee dated February 22, 2005.

                                                 3-40
 1               conservative 1-in-10 peak load forecast. Therefore, PG&E derives its
 2               proposed QF capacity prices based on the cost and operating
 3               parameters, as well as energy benefits and ancillary service benefits, of
 4               existing resources.
 5               (1) Resource Alternatives
 6                   •       PG&E considered the existing resources that the CEC identified
 7                           in its staff white paper, Resource, Reliability and Environmental
 8                           Concerns of Aging Power Plant Operations and Retirements,
 9                           dated August 13, 2004. Out of this set of existing resources,
10                           PG&E has selected a 300 MW existing steam unit, such as
11                           Pittsburg 5 or 6 to develop its proposed QF capacity prices.[ 54]

12               (2) Operating Characteristics of Resource Alternatives
13                           The net energy benefits of the resource alternative is a function
14                   of its operating parameters. Table 3-6 displays the operating
15                   parameters of the two units specified above.

16                                      TABLE 3-6
17                         PACIFIC GAS AND ELECTRIC COMPANY
18                  OPERATING PARAMETERS OF RESOURCE ALTERNATIVES


                      Line
                      No.                                    300 MW steam unit
                         1      Maximum output, MW                  315
                         2      Heat rate, Btu/kWh                 9,735
                         3      Variable O&M (2006$),               2.57
                                 $/MWh


19               (3) Going-Forward Fixed Costs of Resource Alternatives
20                           As described above, the fixed costs of the resource alternative
21                   that are relevant in estimating the QF capacity prices are the
22                   resource’s going-forward fixed costs. Going-forward fixed costs are
23                   costs that do not vary with the resource’s output, but which are
24                   needed to maintain an existing resource in operation.


     [54]   Several of the units identified in the CEC’s white paper have either retired
            (e.g., Morro Bay 1 and 2), are expected to retire (e.g., Pittsburg 7 and
            Contra Cost 6), or have already signed power sales with PG&E for 2006 and
            2007 (e.g., Morro Bay 3 and 4).

                                                 3-41
1   Going-forward fixed costs include insurance, property taxes, and
2   fixed operations and maintenance costs. Going-forward fixed costs
3   do not include depreciation of sunk capital, such as the cost of
4   construction for the resource.
5       The estimated going-forward fixed costs of PG&E’s resource
6   alternatives are shown in Table 3-7.




                            3-42
 1                                  TABLE 3-7
 2                     PACIFIC GAS AND ELECTRIC COMPANY
 3                2006 GOING FORWARD FIXED COSTS ($/KW-YR)(a)


              Line
              No.                                   300 MW steam unit
                1     Fixed O/M                           12.2
                2     Insurance                            3.5
                3     Property tax                         6.9
                4     Going-forward fixed cost            22.6
             _______________
             (a) Fixed O&M costs for the 300 MW existing steam units
                  are based on historic FERC Form 1 data escalated to
                  2006 at 2 percent per year. Insurance and property
                  taxes for existing resources are assumed equal on a
                  $/kW basis to the insurance and property taxes of the
                  peaking MPR resource.


 4                 Based on the above information, the going-forward fixed costs
 5          for resource alternatives in 2006 and 2007 is approximately $23/kW-
 6          yr.
 7      (4) Summary of Proposed Operating Parameters and Going-Forward
 8          Fixed Costs
 9                 PG&E proposes the Commission use the 300 MW existing
10          steam unit with the operating parameters shown in Table 3-6 and a
11          going-forward fixed cost of $23/kW-yr from Table 3-7 to estimate the
12          QF capacity prices for 2006 and 2007.
13                 The next sections show how the QF capacity prices are
14          calculated.
15   b. Allocation of the Annual Going-Forward Fixed Costs of the Resource
16      Alternative
17          After the resource alternative has been identified, the next step in
18      calculating the QF capacity prices is to allocate annual going-forward
19      fixed cost to individual months. PG&E proposes that this allocation be
20      made using the allocation percentages approved in Decision 97-03-017
21      corresponding to each month. For example, for an annual going-
22      forward fixed cost of $23/kW-year, and current Period A (May through
23      October) capacity allocation percentage of 78.59 percent, June’s



                                        3-43
 1                        allocation of the annual going-forward fixed costs is $3.01/kW
 2                        ($23/kW-yr. x 78.59% / 6months = $3.01/kW).
 3              c.        Calculation of QF Capacity Payments
 4                            As described above, PG&E’s avoided cost of meeting its RA
 5                        requirement is the difference between the going-forward fixed cost of the
 6                        resource alternative and the net energy benefits of the resource
 7                        alternative, where the net energy benefits are defined as variable fees
 8                        paid from PG&E to the resource alternative, minus the variable costs of
 9                        the resource alternative. As described earlier in this chapter, the
10                        variable fees paid by PG&E should be equal to day-ahead NP-15 hourly
11                        prices. The variable fees are only paid when the resource is used to
12                        generate electricity; in general, this is when the day-ahead NP-15 hourly
13                        price is greater than the resource’s variable cost. Figure 3-5 displays
14                        graphically the calculation of the avoided cost of capacity.

15                                                FIGURE 3-5
16                                    PACIFIC GAS AND ELECTRIC COMPANY
17                                        AVOIDED COST OF CAPACITY



                                                                              Resource’s net energy benefit




           $/kW-year




                                                                              day-ahead     Alternative resource’s
                                                                      ’s
                                                   alternative resource net   NP15 price         variable cost
                                                   energy benefit
     resource’s going-
     forward fixed cost


                                                   avoided cost of capacity




18                            PG&E proposes to calculate the QF capacity price for each month
19                        as the monthly allocation of the going-forward fixed cost of the resource
20                        alternative, minus that month’s net energy benefit of the resource
21                        alternative. The month’s net energy benefit is the sum of the hourly net


                                                        3-44
 1         energy benefits, for hours when day-ahead NP-15 hourly price is greater
 2         than the variable cost of the resource alternative. In calculating the
 3         variable cost of the resource alternative, PG&E proposes to use
 4         day-ahead burnertip gas prices, and the heat rate and variable operating
 5         and maintenance cost for the 300 MW steam unit displayed in Table 3-
 6         6.
 7               Prior to the expected start of the CAISO day-ahead market, which is
 8         anticipated to provide hourly NP-15 prices, PG&E proposes that the
 9         day-ahead NP-15 hourly price be calculated based on the ICE
10         day-ahead peak and off-peak NP-15 indices, and profiled hourly using
11         hourly factors derived from historical PX prices developed by Energy
12         and Environmental Economics, Inc. (E3), and presently used to estimate
13         avoided costs.
14               PG&E would make a capacity payment only for QF capacity that
15         counts for purposes of satisfying PG&E’s RA requirements and that
16         helps PG&E avoid costs to meet its RA requirements. Existing QFs
17         currently count towards PG&E’s resource adequacy requirements based
18         on their historical performance as specified by Decision 04-10-035. To
19         the extent that new or expiring QFs signed under one-year backstop
20         contracts help PG&E make up meet its RA requirements, they are
21         eligible for capacity payments. However, if PG&E has already met its
22         RA requirement, then additional QF power contracted through the
23         one-year backstop contract would not be eligible.
24               The next section provides numerical estimates of the proposed
25         capacity prices using 2004 market prices.

26   4. Estimated QF Capacity Prices
27         For illustration purposes, PG&E calculated its proposed capacity price
28      using 2004 NP-15 day-ahead prices and Citygate gas prices, an existing
29      300 MW steam unit with the cost and operating parameters described
30      above.




                                        3-45
 1                The going-forward fixed cost needed to maintain the 300 MW unit in
 2             operation during 2004 is $21.76/kW-yr.[55] The net energy benefits
 3             received by PG&E customers is $11.34/kW-yr for 2004. The QF capacity
 4             price for 2004 is therefore $10.42/kW-yr. Therefore PG&E’s as-delivered
 5             capacity price for 2004 would have been $10.42/kW-yr. This as-delivered
 6             capacity price would be allocated monthly using the allocation percentages
 7             approved in Decision 97-03-017 corresponding to each month.

 8          5. Conclusion
 9                 PG&E proposes to pay a near-term capacity price equal to its avoided
10             cost of buying capacity to meet its RA requirements. PG&E will pay that
11             price only for QF capacity that can be used to meet PG&E’s RA
12             requirements.
13                 PG&E requests the Commission adopt PG&E’s capacity pricing
14             proposal, as well as the particular going-forward fixed cost and operating
15             parameters for the resource alternative as proposed in this testimony, for QF
16             capacity prices. This should apply both to as-available capacity for existing
17             QF contracts, and to the one-year backstop contract PG&E proposes as an
18             alternative for new and expiring QF contracts.




     [55]     The steam unit’s going-forward fixed cost and variable O&M were slightly
              lower for 2004 than shown in Tables 3-6 and 3-7 for 2006.

                                               3-46
 PACIFIC GAS AND ELECTRIC COMPANY

             CHAPTER 3

             APPENDIX A

ANALYSIS OF COMPETITIVE CONDITIONS IN

    CALIFORNIA ISO SPOT MARKETS
                   PACIFIC GAS AND ELECTRIC COMPANY
                               CHAPTER 3
                               APPENDIX A
          ANALYSIS OF COMPETITIVE CONDITIONS IN CALIFORNIA ISO
                             SPOT MARKETS

                                      TABLE OF CONTENTS

A. North of Path 15 Day-Ahead Hub ....................................................................3A-1

B. Geographic Scope of the Spot Markets in CA .................................................3A-2

C. Competitive Conditions in the NP-15 Day-Ahead Hub ....................................3A-8

    1. Trends in 2002 to 2005 Day-Ahead Power Prices .....................................3A-8

    2. Implied Market Marginal Heat Rates ........................................................3A-11

    3. Liquidity in NP-15 and Surrounding Hubs ................................................3A-14

    4. Evidence From Other Sources .................................................................3A-15




                                                  3A-i
 1                PACIFIC GAS AND ELECTRIC COMPANY
 2                             CHAPTER 3
 3                             APPENDIX A
 4          ANALYSIS OF COMPETITIVE CONDITIONS IN CALIFORNIA
 5                         ISO SPOT MARKETS


 6   A. North of Path 15 Day-Ahead Hub
 7               The North of Path 15 day-ahead (NP-15 DA) energy market consists of
 8         standardized on-peak and off-peak products. DA transactions are executed one
 9         or more days before power flow according to a pre-determined schedule.[1]
10               DA transactions are executed by market participants (buyers and sellers)
11         using the following means:
12         a. Electronic Trading Platforms: Market participants post anonymous offers to
13               buy or sell DA energy at specific prices and volumes on the electronic
14               trading platform. The electronic trading platform links buyers and sellers.
15               Intercontinental Exchange (ICE) is the leading electronic trading platform for
16               NP-15 DA transactions.
17         b. Voice Brokers: Market participants phone their buy and sell orders to voice
18               brokers who help them to locate a willing counterparty to the transaction.
19         c.    Direct Bilateral Trades: Market participants phone potential counterparties
20               (sellers or buyers of DA energy) to directly negotiate terms of a bilateral
21               transaction.




     [1]        Day-Ahead trading occurs on business days (Monday to Friday) except for
                NERC holidays and WECC scheduled meeting dates. Trading occurs for
                both standard firm on-peak (also called “heavy”) and off-peak (also called
                “light”) products. The NP-15 market is a “6 by 16” market; the on-peak period
                of a week is the hours ending 7 a.m. through 10 p.m. Monday to Saturday,
                except for WECC specified holidays. The off-peak period is the remaining
                hours in the week. Thus, there is an off-peak price for every calendar day
                and there is an on-peak price for every calendar day except Sunday and
                holidays. In weeks without holidays, standard day ahead transactions
                executed: (1) on Monday to Wednesday are for power flowing the following
                calendar day; (2) on Thursday are for power flowing Friday and Saturday, and
                (3) on Friday are for power flowing Sunday and Monday. If a holiday or
                WECC scheduling meeting falls during the week, the day ahead trading
                schedule is adjusted accordingly. The schedule is generally available through
                the WECC website. See the 2005 WECC Preschedule Calendar.

                                                  3A-1
 1             Conceptually, the true NP-15 DA energy price is the volume-weighted
 2         average of the price of all standard firm DA transactions for delivery of “next day”
 3         energy, by whatever means have been used to consummate the trade.

 4   B. Geographic Scope of the Spot Markets in CA
 5             To ascertain the geographic scope of the DA markets in California, I
 6         examined price differentials between the NP-15 and the SP-15, COB, and PV
 7         trading hubs. The price differentials between NP-15 and other hubs can provide
 8         insights on how often the NP-15 hub can be viewed as part of a larger market.
 9         Other things equal, competition is increased with an enlarging of the scope of a
10         market. First, I display the time series of daily DA prices for all four hubs over
11         the forty-three month period January 2002 – July 2005.[2] Figure 3A-1 for
12         on-peak power and Figure 3A-2 for off-peak power show that the four
13         contiguous, wholesale power hubs exhibit the same general pattern of price
14         movement during this period.




     [2]     These are the NP-15 DA power prices reported by ICE from 2002 to 2005.

                                                3A-2
1                                                                          FIGURE 3A-1
2                                                             PACIFIC GAS AND ELECTRIC COMPANY



                                                                        ICE NP-15, SP-15, PV, and COB DA On-Peak Prices
                                                                                    January 2002 - July 2005
                                   130

                                   120

                                   110

                                   100
    ICE DA On-Peak Price ($/MWh)




                                   90

                                   80

                                   70

                                   60

                                   50

                                   40

                                   30

                                   20

                                   10

                                    0
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                                               ICE Daily NP-15 Prices during On-Peak Period              ICE Daily SP-15 Prices during On-Peak Period
                                               ICE Daily PV Prices during On-Peak Period                 ICE Daily COB Prices during On-Peak Period

                                     Source: Daily volume-weighted day-ahead prices from ICE.




                                                                                       3A-3
1                                                                                 FIGURE 3A-2
2                                                                    PACIFIC GAS AND ELECTRIC COMPANY



                                                                              ICE NP-15, SP-15, PV, and COB DA Off-Peak Prices
                                                                                          January 2002 - July 2005
                                      130

                                      120

                                      110

                                      100
      ICE DA Off-Peak Price ($/MWh)




                                      90

                                      80

                                      70

                                      60

                                      50

                                      40

                                      30

                                      20

                                      10

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                                                    5
                                                       ICE Daily NP-15 Prices during Off-Peak Period              ICE Daily SP-15 Prices during Off-Peak Period
                                                       ICE Daily PV Prices during Off-Peak Period                 ICE Daily COB Prices during Off-Peak Period


                                             Source: Daily volume-weighted day-ahead prices from ICE.




3                                        Next, I analyze the statistical correlation between the DA prices in different
4                                     hubs.[3] The values are shown as a matrix in Table 3A-1, on the left side for the
5                                     on-peak power product and on the right for the off-peak product. For these
6                                     two products, the six correlation coefficients for the six pairs of hubs are shown
7                                     on the lower left of the diagonal. All the daily DA market price pairs, for both
8                                     on-peak and off-peak, are highly correlated. For example, for the on-peak price,
9                                     NP-15 has the highest correlation with SP-15 at r = 0.98 and the lowest with PV,


    [3]                                     The correlation coefficient (r) is the standard measure of the degree of linear
                                            relationship between two variables as they change, in this case daily over
                                            time.

                                                                                               3A-4
 1      still high at r = 0.93. (Correlation of 1.00 is perfect, as the diagonal values
 2      indicate).

 3                                            TABLE 3A-1
 4                              PACIFIC GAS AND ELECTRIC COMPANY
                          Correlation of ICE DA Prices Between Hubs
                                    January 2002 - July 2005

                            On-Peak Correlation                   Off-Peak Correlation
                 NP15       SP15        PV         COB     NP15   SP15      PV           COB
     NP15        1.00                                      1.00
     SP15        0.98       1.00                           0.98   1.00
     PV          0.93       0.97        1.00               0.96   0.99      1.00
     COB         0.95       0.93        0.87       1.00    0.97   0.96      0.94         1.00

     Source:
     Daily volume-weighted average DA prices from ICE.



 5           To assess how frequently the NP-15 hub is effectively part of a larger
 6      market, I analyze the DA price differentials on each trading day between the
 7      NP-15 hub and each of the three nearby hubs. Because the cost of transferring
 8      power between hubs is not zero, observed DA price gaps should not be zero. I
 9      determine that two hubs are within the same market if their price differentials are
10      less than the sum of wheeling costs, line losses and 5 percent of the reference
11      hub price.
12           Using this price differential threshold, I calculate the frequency of on-peak
13      trading days in which the NP-15 hub is part of a larger market by season.
14      Columns [2] to [4] of Table 3A-2 present the percentages of on-peak days when
15      the NP-15 hub is considered to be integrated with SP-15, PV, and COB hubs,
16      respectively. Column [5] shows frequencies when the NP-15 is part of a larger
17      market when at least one of the inter-hub price differentials is below the
18      threshold level.




                                                    3A-5
 1                                                         TABLE 3A-2
 2                                           PACIFIC GAS AND ELECTRIC COMPANY


     Frequency of On-Peak Days When NP-15 is Part of a Larger Market: January 2002-July 2005

                                                                        NP-15 Integration With Neighboring Hub(s)
                                Number of
                                                                                                                             With at Least One
                               Trading Days                SP-15                      PV                     COB
                                                                                                                                    Hub
                            [1]                              [2]                      [3]                     [4]                    [5]
     January - November 2002
     Winter                           50                   100.0%                  100.0%                   100.0%                   100.0%
     Spring                           78                    92.3%                  100.0%                   84.6%                    100.0%
     Summer                           78                    29.5%                   69.2%                    24.4%                   74.4%
     Fall                             76                    92.1%                   82.9%                    82.9%                   100.0%
     Annual                           282                   76.2%                   86.9%                    70.2%                   92.9%
     December 2002 - November 2003
     Winter                           75                    92.0%                   96.0%                   100.0%                   100.0%
     Spring                           78                    59.0%                   79.5%                   60.3%                    85.9%
     Summer                           77                    42.9%                   70.1%                   66.2%                    92.2%
     Fall                             76                    72.4%                   89.5%                   98.7%                    100.0%
     Annual                           306                   66.3%                   83.7%                   81.0%                    94.4%
     December 2003 - November 2004
     Winter                           76                    93.4%                   98.7%                   88.2%                    100.0%
     Spring                           78                    44.9%                   93.6%                   92.3%                    100.0%
     Summer                           78                    79.5%                   89.7%                   65.4%                    100.0%
     Fall                             76                    76.3%                   11.8%                   43.4%                    77.6%
     Annual                           308                   73.4%                   73.7%                   72.4%                    94.5%
     January - July 2005
     Winter                           75                   100.0%                   53.3%                   65.3%                    100.0%
     Spring                           78                    97.4%                  100.0%                   82.1%                    100.0%
     Summer                           51                    76.5%                   90.2%                   49.0%                    98.0%
     January - July 2005              204                   93.1%                   80.4%                   67.6%                    99.5%

     Sources and Notes:
     [1] through [4]: Daily DA volume-weighted average price data from ICE.
     [1]: Number of trading days when price indices are reported for each and all of the markets.
     [2]: Percentage of time when NP-15 prices are within 95%-105% of SP-15 prices.
     [3] and [4]: Percentage of time when NP-15 prices are within 95%-105% of the lower of NP-15 and PV/COB prices plus $4/MWh of wheeling/loss charges
     [5]: Percentage of time when at least one of the three price differentials falls within the thresholds as defined in Columns [2] to [4].
       Except for Winter 2002 and Summer 2005, seasonal definitions follow the FERC's convention:
       Winter = December through February; Spring = March through May; Summer = June through July; Fall = September through November.
       Winter 2002 includes Jan and Feb 2002 only. Summer 2005 includes Jun and Jul 2005 only.
       On-Peak period defined as HE 7-22 Mon through Sat, except for NERC holidays.




 3                Table 3A-2 indicates that over the 2002 to 2005 period, the economic
 4         boundaries of the NP-15 on-peak DA hub almost always extends to include
 5         SP-15, PV, or COB. In 2005 to date, the NP-15 hub has been part of a larger
 6         market for almost 100 percent of the on-peak trading days. Over the last few
 7         years, California Independent System Operator (CAISO) DA prices have
 8         converged an increasing share of the time, now reaching 93.1 percent of all
 9         days year-to-date 2005. The non-California hubs have not exhibited such a
10         steady upward trend, but are still often strongly linked. PV links to NP-15




                                                                         3A-6
1         strongly in the spring and summer, while COB prices follow most closely in
2         winter and spring.

3                                                          TABLE 3A-3
4                                            PACIFIC GAS AND ELECTRIC COMPANY


     Frequency of Off-Peak Days When NP-15 is Part of a Larger Market: January 2002-July 2005

                                                                        NP-15 Integration With Neighboring Hub(s)
                                Number of
                                                                                                                             With at Least One
                               Trading Days                SP-15                     PV                     COB
                                                                                                                                    Hub
                           [1]                               [2]                     [3]                      [4]                    [5]
    January - November 2002
    Winter                            59                   89.8%                    81.4%                   100.0%                   100.0%
    Spring                            92                   68.5%                    89.1%                    98.8%                   100.0%
    Summer                            92                   44.6%                    70.7%                    38.0%                    80.4%
    Fall                              91                   42.9%                    44.0%                   100.0%                   100.0%
    Annual                            334                  58.7%                    70.4%                    81.9%                    94.6%
    December 2002 - November 2003
    Winter                            90                   60.0%                    65.6%                    95.3%                   100.0%
    Spring                            92                   77.2%                    73.9%                    92.4%                   95.7%
    Summer                            92                   89.1%                    94.6%                    97.8%                   100.0%
    Fall                              91                   61.5%                    68.1%                   100.0%                   100.0%
    Annual                            365                  72.1%                    75.6%                    96.4%                    98.9%
    December 2003 - November 2004
    Winter                            91                   72.5%                    60.4%                    98.9%                    98.9%
    Spring                            91                   87.9%                    69.2%                    97.8%                   100.0%
    Summer                            92                   55.4%                    45.7%                    77.2%                    91.3%
    Fall                              91                   1.1%                     0.0%                    100.0%                   100.0%
    Annual                            365                  54.2%                    43.8%                    93.4%                    97.5%
    January - July 2005
    Winter                            90                    97.8%                   66.7%                   92.2%                    100.0%
    Spring                            92                    87.0%                   78.3%                   81.1%                    96.7%
    Summer                            61                   100.0%                  100.0%                   96.7%                    100.0%
    January - July 2005               243                   94.2%                   79.4%                   89.2%                     98.8%

    Sources and Notes:
    [1] through [4]: Daily DA volume-weighted average price data from ICE.
    [1]: Number of trading days when at least one price index is reported.
      For NP-15, there is one missing price index during 2004 Spring.
      For COB, there are 3, 9, 2, 5, and 2 missing indices during 2002 Winter, Spring, Fall, 2003 Winter, and 2005 Spring, respectively.
    [2]: Percentage of time when NP-15 prices are within 95%-105% of SP-15 prices.
    [3] and [4]: Percentage of time when NP-15 prices are within 95%-105% of the lower of NP-15 and PV/COB prices plus $3/MWh of wheeling/loss charges.
    [5]: Percentage of time when at least one of the three price differentials falls within the thresholds as defined in Columns [2] to [4].
      Except for Winter 2002 and Summer 2005, seasonal definitions follow the FERC's convention:
      Winter = December through February; Spring = March through May; Summer = June through July; Fall = September through November.
      Winter 2002 includes Jan and Feb 2002 only. Summer 2005 includes Jun and Jul 2005 only.
      On-Peak period defined as HE 7-22 Mon through Sat, except for NERC holidays.
      The remaining constitutes Off-Peak period.




                                                                         3A-7
 1          There is an even smaller degree of separation for the off-peak prices during
 2      the 2002 to 2005 period. Table 3A-3 presents the frequency of market
 3      integration for the NP-15 DA off-peak product. The result shows that for
 4      98.8 percent of the off-peak trading days during 2005 the NP-15 hub is part of a
 5      larger DA market; 94.2 percent of the time the CAISO is a single DA market.

 6   C. Competitive Conditions in the NP-15 Day-Ahead Hub
 7          Having determined that the NP-15 hub almost always includes the SP-15,
 8      PV, and COB hubs, I now turn to a diagnosis of competitive conditions in this
 9      integrated market. First, I review historical DA power prices in these hubs from
10      2002 to 2005. Second, I examine the price mark-up levels in the NP-15 market.
11      Third, I add the other three western hubs I have been analyzing to my earlier
12      assessment of the NP-15 hub’s liquidity as measured against the Federal
13      Energy Regulatory Commission (FERC) standard, discussed above in
14      Section E, sub-section 4. Finally, I review the outlook of the demand and supply
15      conditions in the California power market.

16      1. Trends in 2002 to 2005 Day-Ahead Power Prices
17              NP-15 DA power prices over the past three and a half years have been
18          reasonable for both on-peak and off-peak periods when compared to DA
19          prices in the neighboring hubs. As shown above in Figures 3A-1 and 3A-2,
20          the DA on-peak and off-peak prices, respectively, for NP-15, SP-15, PV, and
21          COB have generally risen since 2002. Figures 3A-3 and 3A-4 present the
22          mean, median, maximum, minimum, and standard deviation of these DA
23          prices during the 2002 to 2005 period for on-peak and off-peak deliveries,
24          respectively. These key statistics indicate that DA price levels of these hubs
25          were generally in the same range each year.




                                            3A-8
1                                                              FIGURE 3A-3
2                                                  PACIFIC GAS AND ELECTRIC COMPANY

                                                        Comparison of On-Peak DA Price Level Key Statistics
                                                        NP-15, SP-15, PV, and COB: January 2002 - July 2005

                    140
                                      2002                          2003                           2004                        January - July 2005

                    120



                    100
    Price ($/MWh)




                    80



                    60



                    40



                    20



                     0
                          NP15 SP15    PV    COB         NP15 SP15     PV    COB         NP15 SP15        PV    COB           NP15 SP15    PV    COB

                                  Minimum            1st Quantile           Mean          Median               3rd Quantile          Maximum

                             Source: Daily volume-weighted average DA prices from ICE.




3                             Figure 3A-4 presents key statistics of the NP-15, SP-15, PV, and COB
4                         DA off-peak prices series. NP-15 DA off-peak prices followed the same
5                         course as those in the SP-15, PV and COB hubs over the 2002 to 2005
6                         period, although at slightly higher levels.




                                                                             3A-9
1                                                                  FIGURE 3A-4
2                                                     PACIFIC GAS AND ELECTRIC COMPANY

                                                            Comparison of Off-Peak DA Price Level Key Statistics
                                                            NP-15, SP-15, PV, and COB: January 2002 - July 2005

                      140
                                         2002                           2003                          2004                    January - July 2005

                      120



                      100
      Price ($/MWh)




                      80



                      60



                      40



                      20



                       0
                             NP15 SP15 PV       COB        NP15 SP15 PV        COB          NP15 SP15 PV     COB            NP15 SP15 PV      COB

                                      Minimum            1st Quantile          Mean          Median          3rd Quantile          Maximum

                                Source: Daily volume-weighted average DA prices from ICE.




3                                 Although the market has experienced some modest price spikes as
4                            shown in Figure 3A-5, the prices rarely exceeded $91.87/MWh, which is the
5                            level at which the CAISO’s automatic mitigation procedure (AMP) starts
6                            examining seller bids.[4]


7




    [4]                     The market power mitigation protocols of the CAISO have been in place for
                            several years. These protocols act to automatically reduce clearing prices in
                            the real-time (RT) markets when any bidder submits a real-time sales bid that
                            (a) is either $100 or 200 percent greater than their reference bid; (b) causes a
                            price increase of either $50 or 200 percent or more in the new market clearing
                            price; and (c) results in clearing price above $91.87 (a threshold set by the
                            FERC). The incidences in Figure 3A-5 in 2003 and 2005 where market prices
                            exceeded $91.87 were not violations of the CAISO AMP because bids did not
                            exceed both the conduct and impact thresholds.

                                                                               3A-10
 1                                                                        FIGURE 3A-5
 2                                                            PACIFIC GAS AND ELECTRIC COMPANY



                                                                                          NP-15 DA On-Peak and Off-Peak Prices
                                                                                                January 2002 - July 2005
                     140

                     130

                     120                $91.87/MW h CAISO AMP
                                        Trigger Price Screen
                     110

                     100

                      90
                                                                                                                                                     DA On-peak Prices
     Price ($/MWh)




                      80

                      70

                      60

                      50

                      40

                      30

                      20

                      10                                    DA Off-peak Prices

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                                         2




                                                                                                                                                                                                       4
                                                                                      2
                                                 2




                           Source: Daily volume-weighted day-ahead prices from ICE.




 3               2. Implied Market Marginal Heat Rates
 4                                  Increases in DA prices during this period may have been caused by a
 5                         jump in natural gas prices. To determine the extent to which gas prices
 6                         caused electric price increases, we review the movement of electricity and
 7                         gas prices. Figure 3A-6 shows that the electricity and gas prices in the
 8                         NP-15 region generally moved in tandem, and most of the NP-15 DA price
 9                         spikes over the 2002 to 2005 period correspond to concurrent gas price
10                         spikes.




                                                                                                          3A-11
 1                                                                                      FIGURE 3A-6
 2                                                                         PACIFIC GAS AND ELECTRIC COMPANY



                                                                  Day-ahead Electricity Prices (NP15) vs. Gas Prices (PG&E City Gate)
                                                                                        January 2002 - July 2005
                                    140                                                                                                               11


                                                                                                                                                      10
                                    120
                                                                                                                                                      9


                                    100                                                                                                               8
     DA Electricity Price ($/MWh)




                                                                                                                                                      7




                                                                                                                                                           Gas Price ($/MMBtu)
                                    80                                                          Gas Prices
                                                                                                                                                      6


                                                                                                                                                      5
                                    60

                                                                                                                                                      4

                                    40                                                                                                                3


                                                                                                                                                      2
                                    20                                                            Off-Peak NP15 Prices
                                                                          On-Peak NP15 Prices                                                         1


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 3                                                      To further explore the linkage between gas and electric prices, I
 4                                         calculate the implied market marginal heat rate for DA prices using DA gas
 5                                         prices delivered at each power hub, as reported by Gas Daily. An implied
 6                                         market marginal heat rate is the ratio of DA power price to DA gas price plus
 7                                         $2/MWh for assumed variable operations and maintenance. When
 8                                         multiplying the ratio by 1,000, the value can be thought of loosely as the
 9                                         heat rate of the marginal generating unit in the market.
10                                                      The results are presented in Figures 3A-7 and 3A-8, which depict the
11                                         monthly average NP-15 DA implied market marginal heat rates during the
12                                         period 2002 to 2005 for on-peak and off-peak, respectively. The results
13                                         shown in Figures 3A-7 and 3A-8 indicate that even before correcting for
14                                         non-fuel inflation, there has been no upward trend in marginal heat rates in




                                                                                                 3A-12
1                                 any of the four main western hubs.[5] This is an indication that price
2                                 increases are due almost entirely to higher gas prices.

3                                                               FIGURE 3A-7
4                                                  PACIFIC GAS AND ELECTRIC COMPANY



                                                           Implied Heat Rates By Month
                                                      January 2002 - July 2005 On-Peak Period


                          16000
                                                                                                                                                      NP-15
                                                                                                                                                      SP-15
                          14000                                                                                                                       PV
                                                                                                                                                      COB

                          12000


                          10000
      Implied Heat Rate




                          8000


                          6000                                                                         Summary of Seasonal Averages of Implied Heat Rates
                                                                                                                       On-Peak Period
                                                                                                                               Implied Heat Rate
                                                                                     Season                  NP-15            SP-15            PV           COB

                          4000                                                       Summer 02
                                                                                     Non-Summer 02
                                                                                                               11085
                                                                                                               9707
                                                                                                                               12090
                                                                                                                               9811
                                                                                                                                              12629
                                                                                                                                              9087
                                                                                                                                                            7632
                                                                                                                                                            8775
                                                                                     Summer 03                  9691           10336          10623         8626
                                                                                     Non-Summer 03             8737            9104           8410          7928
                                                                                     Summer 04                  9454            9736          9269          8386
                                                                                     Non-summer 04              8982            9050          8010          8103
                                                                                     Summer 05                  9176            9473          9528          8047
                          2000                                                       Non-Summer 05
                                                                                     2002
                                                                                                               8315
                                                                                                               10051
                                                                                                                               8347
                                                                                                                               10381
                                                                                                                                              7700
                                                                                                                                              9972
                                                                                                                                                            7571
                                                                                                                                                            8489
                                                                                     2003                      8975            9412           8963          8102
                                                                                     2004                      9100            9221           8325          8174
                                                                                     Jan 2005 - July 2005       8561            8669           8222         7707


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    [5]                       In the last two months there has been a marked increase in market implied
                              heat rates. This is not unusual for summer, and too early to label a trend, but
                              it does bear watching in the future.

                                                                   3A-13
 1                                                                   FIGURE 3A-8
 2                                                      PACIFIC GAS AND ELECTRIC COMPANY


                                                                Implied Heat Rates By Month
                                                           January 2002 - July 2005 Off-Peak Period


                           10000
                                                                                                                                                         NP-15
                           9000                                                                                                                          SP-15
                                                                                                                                                         PV
                                                                                                                                                         COB
                           8000


                           7000
       Implied Heat Rate




                           6000


                           5000


                           4000
                                                                                                           Summary of Seasonal Averages of Implied Heat Rates
                                                                                                                           Off-Peak Period
                                                                                                                                   Implied Heat Rate
                           3000                                                          Season                  NP-15            SP-15            PV           COB
                                                                                         Summer 02                  5731           5173           4827          3914
                                                                                         Non-Summer 02              7004           6768           5951          6759
                                                                                         Summer 03                  6734           6736           6465          6585
                                                                                         Non-Summer 03              6404           6235           5728          6299
                           2000                                                          Summer 04                  6752           6372           5793          6546
                                                                                         Non-Summer 04              6880           6486           5794          6773
                                                                                         Summer 05                  5430           5503           5298          5001
                                                                                         Non-Summer 05              5952           5941           5419          6107
                                                                                         2002                       6686           6369           5670          6048
                           1000                                                          2003                       6486           6360           5913          6370
                                                                                         2004                       6848           6458           5794          6716
                                                                                         Jan 2005 - July 2005       5803           5816           5385          5791


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 3                         3. Liquidity in NP-15 and Surrounding Hubs
 4                                          The liquidity of a product market is also an indicator of the competitive
 5                                 condition of that market. As discussed above in Chapter 3, Section C,
 6                                 sub-section 4, the NP 15 hub is highly liquid for both on-peak and off-peak
 7                                 products. ICE’s average daily transactions for NP-15 DA delivery, including
 8                                 average daily volume, average daily number of transactions, and average
 9                                 daily number of counterparties, over the three and a half year period easily
10                                 exceeded all of the FERC’s market liquidity criteria set out in its recent
11                                 order.[6] The average daily on-peak volume traded through ICE at NP-15 is
12                                 13,361 MWh, more than six times the FERC minimum required standard of
13                                 2,000 MWh per day. Additionally, NP-15’s adjacent hubs, SP-15, PV and




     [6]                       Order Regarding Future Monitoring of Voluntary Price Formation, Use of
                               Price Indices in Jurisdictional Tariffs, and Closing Certain Tariff Dockets,
                               109 FERC ¶ 61,184 (Nov. 19, 2004).

                                                                           3A-14
 1              COB, are shown with the ICE historical trading data to have levels of trading
 2              activity that meet the FERC liquidity standard, as contained in Table 3A-4.

 3                                         TABLE 3A-4
 4                           PACIFIC GAS AND ELECTRIC COMPANY
 5                COMPARISON OF NP-15, SP-15, PV, AND COB DA MARKET ACTIVITIES
 6                           ICE DATA: JANUARY 2002 - JULY 2005*


               Criteria                  On-peak                           Off-peak
                              SP-15    NP-15     PV      COB     SP-15   NP-15    PV     COB

           Average Daily      18,107   13,361   13,668   5,240   6,132   4,921   4,057   2,532
           Volume (MWh)

           Average Number       45      32       33       13      22      18      15      9
               of Daily
            Transactions

           Average Number       20      18       20       12      15      14      13      9
                 of
            Counterparties
             Transacting
 7                        *Note: The values for each of the delivery hubs are averages
 8                  calculated over the forty-one 90 day (or three month) periods from
 9                  January 2002 to July 2005.

10          4. Evidence From Other Sources
11                  My finding that the NP-15 hub and its broader market are workably
12              competitive is supported by the CAISO evaluation of the short-term energy
13              market. The CAISO’s Department of Market Analysis (DMA) calculates the
14              real-time price-to-cost mark-up index as an indicator of the competitiveness
15              of the real-time market. In 2003 this index ranged between zero and
16              20 percent with the average index below 10 percent, indicating that “…short-
17              term wholesale energy markets produced very competitive outcomes in
18              2003.”[7] The 2004 monthly mark-up index varied from as low as
19              1.2 percent to as high as 22.5 percent.[8]
20                  Additionally, the CAISO DMA’s 2003 Annual Report on Market Issues
21              and Performance, states: “[a] review of market performance shows that


     [7]      Department of Market Analysis – California ISO, 2003 Annual Report on
              Market Issues and Performance p. 2-18 (April 2004).
     [8]      Department of Market Analysis – California ISO, 2004 Annual Report on
              Market Issues and Performance p. 2-15 (April 2005).

                                                 3A-15
1           2003 resulted in the most competitive short-term energy market since the
2           start of the restructured California electric market in 1998.”[9] The residual
3           supplier indices (RSI) calculated by the CAISO DMA indicate a healthy
4           market, with suppliers pivotal in less than 1.5 percent, 0.2 percent, and
5           0.5 percent of the hours in 2002, 2003, and 2004, respectively.[10]




    [9]    Id. at p. ES-1.
    [10]   Id. at p. ES-13; see also Department of Market Analysis – California ISO,
           2002 Annual Report of Market Issues and Performance p. ES-12 (April 2003).

                                            3A-16
       PACIFIC GAS AND ELECTRIC COMPANY

                   CHAPTER 3

                  APPENDIX B

CALCULATION OF OVERPAYMENTS FROM MANDATED QF

 SO1 EXTENSIONS PURSUANT TO DECISIONS 03-12-062

                 AND 04-01-050
               PACIFIC GAS AND ELECTRIC COMPANY
                           CHAPTER 3
                           APPENDIX B
CALCULATION OF OVERPAYMENTS FROM MANDATED QF SO1 EXTENSIONS
          PURSUANT TO DECISIONS 03-12-062 AND 04-01-050

                                    TABLE OF CONTENTS

A. SRAC Energy Overpayment (Berry)................................................................3B-2

B. As-delivered Capacity Overpayment (Strauss)................................................3B-2




                                                3B-i
 1             PACIFIC GAS AND ELECTRIC COMPANY
 2                         CHAPTER 3
 3                         APPENDIX B
 4    CALCULATION OF OVERPAYMENTS FROM MANDATED QF SO1
 5   EXTENSIONS PURSUANT TO DECISIONS 03-12-062 AND 04-01-050

 6       The following section quantifies the overpayment for short-run avoided cost
 7   (SRAC) energy and as-delivered capacity due to the one-year and five-year
 8   extensions of SO1 agreements mandated by Decisions 03-12-062 and 04-01-050,
 9   respectively. These transitional SO1 (TSO1) extensions are applicable to power
10   purchase agreements that expired between January 1, 1998 and December 31,
11   2005. Decision 03-12-062 directed the utilities to extend then expired or expiring
12   qualifying facility (QF) contracts for one year until December 31, 2004. Later, on
13   January 22, 2004, in Decision 04-01-050, the California Public Utilities Commission
14   (CPUC or Commission) ordered the utilities to sign five year TSO1 power purchase
15   agreements with QFs wishing to provide power at SRAC prices.
16       In Southern Cal. Edison Co. v. Public Utilities Com., 128 Cal. App. 4th 1 (2005),
17   the Court of Appeal recognized that the Commission had opened this proceeding,
18   Rulemaking 04-04-025, to reform SRAC pricing and noted that the Commission’s
19   orders to the utilities to offer the TSO1 power purchase agreements might have
20   caused utility customers to pay more than the utilities’ avoided costs for QF power.
21   Id. at p. 12. The Court further noted that it is the Commission’s duty to apply any
22   new SRAC formula retroactively to the TSO1 power purchase agreements “to arrive
23   at a more accurate SRAC” because “[t]he Commission does not have the power to
24   thwart Congressional intent by having a policy inconsistent with that set forth in
25   PURPA.” Id. at p. 12. Below, Pacific Gas and Electric Company (PG&E or the
26   Company) calculates the overpayments through June 2005 to establish the amount
27   of refund that the QFs operating under the TSO1 power purchase agreements
28   should be required to return to utility customers if PG&E’s proposals in this
29   proceeding for amending the SRAC energy and as-delivered capacity prices are
30   adopted. PG&E calculates that as of June 30, 2005, its customers have overpaid for
31   QF power from these contracts by $32 million, $20 million from SRAC energy
32   overpayments and that in 2004 and 2005, PG&E customers will overpay $12 million
33   for as-delivered capacity.


                                              3B-1
 1   A. SRAC Energy Overpayment (Berry)
 2          To calculate the SRAC energy overpayment, I compiled monthly summaries
 3      of the volume of QF energy that was subject to the mandated extension under
 4      SO1 prices and terms. I refer to this volume as transitional SO1s or TSO1s.
 5      For each month, I calculated the price premium paid to these TSO1s, i.e., the
 6      difference between the average NP-15 DA price and the posted SRAC energy
 7      price for each month. Finally, I multiplied the TSO1 volume by the price
 8      premium paid for each month to calculate the amount of overpayments.
 9      Ignoring any adjustments for interest, a simple summation of the monthly
10      overpayments yields $20,046,294 as of June 2005. This amount is a fair, if not
11      conservative estimate of energy overpayments.

12                                     TABLE 3B-1
13                         PACIFIC GAS AND ELECTRIC COMPANY
14                            SRAC ENERGY OVERPAYMENT
15                                      $MILLION


                    AVG NP-15     SRAC         (SRAC) -      TSO1 Volume    Savings At DA
                    DA PRICE      Energy        (NP15)          KWh             NP15
                     $/MWh         Price        $/MWh
                                  $/MWh
          Jan-04          45.85       68.46          22.61     52,285,979   $    1,182,186
          Feb-04          45.24       67.84           22.6     46,696,594   $    1,055,343
          Mar-04          39.14        60.7          21.56     49,849,538   $    1,074,756
          Apr-04             44       62.25          18.25     41,575,759   $      758,758
         May-04           51.91       51.35          -0.56     62,710,242   $      (35,118)
          Jun-04          47.46       56.64           9.18     81,257,233   $      745,941
          Jul-04          53.03       53.91           0.88     80,743,247   $       71,054
          Aug-04          51.25       54.56           3.31     75,722,613   $      250,642
          Sep-04          44.54       47.23           2.69     71,447,216   $      192,193
          Oct-04          50.69       46.85          -3.84     85,035,719   $     (326,537)
          Nov-04          58.51       90.95          32.44     85,151,161   $    2,762,304
          Dec-04           57.8       79.49          21.69     85,140,135   $    1,846,690
          Jan-05          50.34       74.46          24.12     81,227,903   $    1,959,217
          Feb-05           48.7       73.08          24.38     76,765,379   $    1,871,540
          Mar-05          51.01       71.61           20.6     81,548,654   $    1,679,902
          Apr-05          53.41       84.11           30.7     92,189,778   $    2,830,226
         May-05           42.89       61.37          18.48     68,287,145   $    1,261,946
          Jun-05          43.81       54.23          10.42     83,037,550   $      865,251

                                                                            $   20,046,294

16   B. As-delivered Capacity Overpayment (Strauss)
17          For purposes of quantifying the capacity overpayments in 2004, I used the
18      actual amounts of as-delivered capacity purchased from QFs under TSO1


                                              3B-2
 1              contracts. For 2005, I estimated the amount of as-delivered capacity associated
 2              with the extended contracts.
 3                    Given that the avoided capacity cost calculated in Chapter 3, Section E was
 4              only about $10/kW-yr, and the as-delivered capacity prices were about $65 and
 5              $66/kW-yr for 2004 and 2005, respectively, the as-delivered capacity
 6              overpayments for the mandated contract extensions are approximately
 7              84 percent[1] of the total capacity payments. The following table summarizes
 8              the calculation.

 9                                               TABLE 3B-2
10                                   PACIFIC GAS AND ELECTRIC COMPANY
11                                  AS-DELIVERED CAPACITY OVERPAYMENT
12                                                $MILLION


                                                                Avoided                     Capacity over-
Line                    Capacity payment   Capacity price     capacity cost   Overpayment     payment
No.            Year        $millions         $/kW-yr            $/kW-yr            %          $millions
     1    2004               6.66              64.93             10.42           84%             5.59
     2    2005               7.80              66.43             10.42           84%             6.58
     3    Sum               14.46                                                               12.17


13                    In summary, the as-delivered capacity overpayments for the mandated
14              TSO1 contract extensions in from January 1, 2004 through December 2005 are
15              approximately $12 million.




         [1]      This is $65 for 2004 (or $66 for 2005) less $10, divided by $65 or $66.

                                                       3B-3
PACIFIC GAS AND ELECTRIC COMPANY

           CHAPTER 4

   OUTLINE OF PG&E PROPOSAL
                            PACIFIC GAS AND ELECTRIC COMPANY
                                        CHAPTER 4
                                OUTLINE OF PG&E PROPOSAL

                                          TABLE OF CONTENTS

A. Introduction (De Rosa) ...................................................................................... 4-1

    1. Prices Paid Under Current Standard Offer Agreements Far Exceed
       PG&E’s Avoided Cost .................................................................................. 4-1

    2. The Commission Should Not Require New Long-Term QF Power
       Purchase Agreements Given the Provisions of the Energy Policy Act of
       2005 That Eliminate the PURPA Must Take Obligation if a Competitive
       Wholesale Market Exists .............................................................................. 4-5

    3. Competitive Solicitations for Firm Power Products Are an Appropriate
       Means to Implement PURPA in Today’s Deregulated Market...................... 4-6

    4. PG&E’s Competitive Solicitations................................................................. 4-8

    5. PG&E Proposes to Continue Bilateral Negotiations ................................... 4-10

    6. PG&E’s Short-Term Contract Option ......................................................... 4-10

         a. Energy Price for Short-Term Purchases in Proposed Agreements....... 4-12

         b. RA Capacity Contract Option................................................................ 4-13

    7. PG&E’s QF Contracts Expire Gradually Over the Next 10 Years............... 4-13

    8. PG&E’s Proposal Furthers the Commission’s Policy Objectives................ 4-14

         a. PG&E’s Proposal Reduces the Likelihood of Additional Stranded
            Costs From Future QF Contracts.......................................................... 4-14

         b. PG&E’s Proposal Supports the RPS Program...................................... 4-15

         c. PG&E’s Proposal Furthers Least Cost – Best Fit Procurement ............ 4-15

         d. PG&E’s Proposal Supports Resource Adequacy Standards ................ 4-16

B. Implementation of PURPA in Other States (Lauckhart)................................... 4-16

    1. Introduction and Summary ......................................................................... 4-16

    2. Research Regarding Other States’ Implementation of PURPA.................. 4-17

         a. Overview............................................................................................... 4-17




                                                         4-i
                            PACIFIC GAS AND ELECTRIC COMPANY
                                        CHAPTER 4
                                OUTLINE OF PG&E PROPOSAL

                                          TABLE OF CONTENTS

                                                 (CONTINUED)

        b. States Using Solicitations to Determine Avoided Cost Rates ............... 4-18

        c. FERC Decisions Regarding QF Solicitations ........................................ 4-20

            (1) Texas............................................................................................... 4-22

            (2) New York......................................................................................... 4-24

            (3) Louisiana ......................................................................................... 4-25

            (4) Florida ............................................................................................. 4-28

            (5) Washington ..................................................................................... 4-29

        d. States Using Published or Administratively Determined Avoided
           Cost Rates ............................................................................................ 4-31

        e. States That Determine Avoided Costs on a Contract-By-Contract
           Basis ..................................................................................................... 4-32

    3. Conclusions and Observations................................................................... 4-32

C. Load and Resources (La Flash) ...................................................................... 4-33

    1. PG&E’s Long-Term Plan ............................................................................ 4-33

    2. Re-Contracting Options.............................................................................. 4-35




                                                          4-ii
 1                   PACIFIC GAS AND ELECTRIC COMPANY
 2                               CHAPTER 4
 3                       OUTLINE OF PG&E PROPOSAL


 4   A. Introduction (De Rosa)
 5          Pacific Gas and Electric Company (PG&E or the Company) proposes to
 6      procure power from new qualifying facilities (QFs) and QFs with expiring
 7      contracts in three ways:
 8      1. Competitive all-source and renewable solicitations;
 9      2. Bilateral negotiations; and
10      3. One-year market-based Edison Electric Institute (EEI) power contracts.
11          PG&E’s proposal seeks to advance the California Public Utilities
12      Commission’s (CPUC or Commission) and state’s energy procurement policy
13      objectives by:
14      •   Providing customers reliable power delivery at market-based prices;

15      •   Procuring energy through Commission-ordered all-source competitive
16          solicitations; and

17      •   Satisfying Public Utility Regulatory Policies Act of 1978 (PURPA)
18          requirements for QF purchases.

19          PG&E’s proposal is consistent with the Commission’s All-Source and RPS
20      Solicitation Bidding Guidelines, including the requirement to conduct utility
21      procurement through all-source open solicitations and the employment of
22      Least-Cost Best-Fit (LCBF) methodology to evaluate bids. It is also consistent
23      with Commission policy on resource adequacy and reduces the risk of future
24      stranded cost.

25      1. Prices Paid Under Current Standard Offer Agreements Far
26          Exceed PG&E’s Avoided Cost
27              PG&E now purchases most QF power through standard offer power
28          purchase agreements. These long-term contracts for baseload or
29          intermittent power, executed in the 1980s, are now among PG&E’s most
30          expensive power supplies – even more expensive than the long-term




                                              4-1
 1          baseload contracts the California Department of Water Resources (CDWR)
 2          signed in 2001 at the height of the energy crisis.[1]
 3              PG&E’s customers paid QFs a total of $1.5 billion in 2004. QFs
 4          provided 24 percent of the power delivered to PG&E’s customers that year,
 5          but the cost of this power was 31 percent of PG&E’s total supply cost.
 6          PG&E estimates that in 2004 alone the cost of QF energy was at least
 7          $381 million more than PG&E otherwise would have spent for the same
 8          volume of power in the wholesale market.
 9              Table 4-1 compares the average 2004 QF price of $80/MWhr with the
10          2004 Renewable Portfolio Standard (RPS) Market Price Referent (“MPR”)
11          issued by the Commission.[2] QF contracts supply baseload or intermittent
12          power while the MPR is for a baseload supply. In the past 3 years, PG&E
13          has entered into 8 new power purchase agreements (PPAs) with terms
14          ranging from 5-20 years for baseload or intermittent power. Because each
15          PPA was priced below the Commission’s 2004 MPR of $59.99/MWh, the
16          comparison between the MPR and the average 2004 QF price
17          conservatively estimates the QFs’ above-market costs.
18              The MPR is an appropriate market proxy because it is an independent,
19          transparent rate that is close to—though higher than—the prices in
20          long-term contracts PG&E executed in the past three years. As Table 4-1
21          shows, comparing the MPR against the QF costs results in an over-market
22          cost of $381 million, or 33 percent.[3]




     [1]   For example, in 2004, PG&E paid an average rate of $80/MWh for its QF
           contracts. CDWR’s two 10-year, 7x24, 1,000 MW contracts originally with
           Calpine Energy Services, LPP had rates of $58.60/MWh and $59.60/MWh,
           respectively.
     [2]   CPUC Resolution E-3942, July 21, 2005. The 2004 MPR reflects a 2005
           on-line date.
     [3]   Another relevant comparison is between the cost of QF power and the cost
           PG&E would have paid on the NP-15 day-ahead market for the same volume.
           The comparable 2004 rates are $80/MWhr for QF power vs. the average
           2004 Dow Jones NP-15 price for Day-Ahead deliveries of $49/MWhr. This
           comparison results in an above-market cost of $591 million, or 63 percent
           above market, for the 19,049 GWh of QF volume. $591 million translates to
           more than ¾ of a cent/kWh of PG&E’s average 2004 retail rate.

                                            4-2
 1                                  TABLE 4-1
 2                     PACIFIC GAS AND ELECTRIC COMPANY
 3             COMPARISON OF QF RATES WITH MARKET PRICE REFERENT


     Line
     No.
      1      2004 Avg. QF Price      $80/MWh
      2      2004 MPR                $60/MWh
      3      QF Price Above MPR      $20/MWh
      4      2004 Total QF Volume    19,049 GWh
      5      Above-Market Cost       $20/MWh * 19,049 GWh = $381 Million

 4            Comparing the price and terms of PG&E’s QF contracts to recent
 5        market-based PPAs entered into by the other utilities also shows that the QF
 6        contracts are above market. Table 4-2 compares the capacity price, heat
 7        rate, and dispatchability of QFs against:
 8        (a) 2004 MPR (as a reference). The MPR is based on the long-term cost of
 9            building and operating a new combined cycle generating plant in
10            California;
11        (b) Otay Mesa contract between San Diego Gas and Electric Company
12            (SDG&E) and Calpine’s Otay Mesa Energy Center LLC.; approved by
13            the CPUC in June, 2004 Decision 04-06-011;
14        (c) Palomar project purchased by SDG&E, also approved in
15            Decision 04-06-011; and
16        (d) Mountainview contract between Southern California Edison Company
17            (SCE) and Mountainview Power Company, approved by the CPUC in
18            Decisions 03-12-0-59 and 04-04-037.
19            These comparisons reflect CPUC-approved benchmarks for long-term
20        procurement opportunities other California utilities have realized since 2003.
21        Further, as Table 4-2 shows, each of these contracts contain significantly
22        lower annual fixed costs and heat rates than PG&E’s QF contracts, and, in
23        contrast to the QF contracts, are dispatchable.




                                           4-3
       1                                               TABLE 4-2
       2                                  PACIFIC GAS AND ELECTRIC COMPANY
       3                      PG&E 2004 QF COSTS VS. MPR AND RECENT MARKET CONTRACTS


                                                                                   In Service        Annual
Line                                       Build                        Size      Capital Cost     Fixed Cost    2004 Heat Rate
No.          Contract          Term        Year     Configuration      (MW)          ($/kW)         ($/kW-yr       (Btu/kWh)         Dispatchable

  1        Average          15-30 years            NA                 Various           NA         $202(a)             9,800              No
            PG&E QF
  2        2004 baseload    20 years      2006     Multi-unit         Various          $734        $103(b)             7,193             Yes
            MPR                                     Combined
                                                    Cycle
  3        Otay Mesa        10 years               2x1 GE Frame       573               NA          $117               6,971             Yes
                                                    7FA
  4        Palomar                        2006     2x1 GE Frame       503              $962         $133(c)            7,229(d)          Yes
                                                    7FA
  5        Mountainview                   2006     Two 2x1 GE         1054             $667          $95               7,245             Yes
                                                    Frame 7FA
_______________
(a)    Some of PG&E’s ISO4 contracts include a payment of up to $188/kW-yr for as-delivered capacity above firm capacity amounts.
(b)    Annual Fixed Cost calculated with cash flow model and methodology used to develop the 2004 MPR.
(c)    The Annual Fixed Cost of the Palomar and Mountainview projects are not public. The conversion of In-Service Capital Cost ($/kW) to Annual
       Fixed Cost ($/kW-year) use the same financial inputs and operational characteristics as those used in the 2004 baseload MPR, a similar
       combined cycle project.
(d)    The new and clean rates of Palomar and Mountainview are converted to average heat rates using the 2004 MPR baseload assumption of
       3.5 percent heat rate degradation.


       4                       The lack of dispatchability and limited curtailment rights in the standard
       5                   offer agreements increase the costs of QF power for utility customers. In
       6                   2004, if PG&E could have curtailed QF purchases when market prices were
       7                   lower than the variable cost of the QF contracts, customers would have
       8                   saved an average of $13.5/MWh on the 19,049,000 MWh of QF energy, for
       9                   a total savings of approximately $258 million.[4] This cost to customers
      10                   attributable to from the lack of dispatchability shows that QF contract
      11                   terms—as well as prices—add enormously to QF overpayments.




             [4]        The average savings was derived by comparing the QF SRAC rate with peak
                        and off peak Intercontinental Exchange (ICE) NP-15 indices for Day Ahead
                        deliveries. The ICE NP-15 Day-Ahead indices reflect a firm delivery product
                        that requires the seller to pay replacement costs for non-delivery, a more
                        valuable product than unit-contingent deliveries by QFs that have an annual
                        outage allowance.

                                                                       4-4
 1   2. The Commission Should Not Require New Long-Term QF Power
 2      Purchase Agreements Given the Provisions of the Energy Policy
 3      Act of 2005 That Eliminate the PURPA Must Take Obligation if a
 4      Competitive Wholesale Market Exists
 5          On August 8, 2005, the Energy Policy Act of 2005 (the Act) was
 6      enacted. The Act eliminated PURPA’s mandatory purchase obligations
 7      where a wholesale market meeting certain criteria exists subject to Federal
 8      Energy Regulatory Commission (FERC) approval. Section 1253 (a)
 9      (amending 16 U.S.C. 824a-3) provides that an electric utility is no longer
10      required to enter into a new contract or obligation to purchase electric
11      energy from a QF if FERC determines the QF has access to:
12      (1) Independently administered, auction-based day ahead and real-time
13          wholesale markets for the sale of electric energy, and wholesale
14          markets for long-term sales of capacity and electric energy; or
15      (2) Nondiscriminatory interconnection and transmission services that are
16          provided by a FERC-approved regional transmission entity and
17          administered pursuant to an open-access transmission tariff, and
18          competitive capacity and electric energy wholesale markets; or
19      (3) Wholesale markets for the sale of capacity and electric energy that are,
20          at a minimum, of comparable quality to the markets in (1) and (2).
21          The Act provides that an electric utility may file an application with FERC
22      for relief from the mandatory purchase obligation on a service territory-wide
23      basis describing why the conditions set forth above have been met.
24          The Act also amends current standards for cogeneration facilities to
25      qualify as QFs. A new Section 16 U.S.C. 824a-3 (n) requires FERC to issue
26      new regulations within 180 days of the enactment of the Act revising the
27      criteria for new qualifying cogeneration facilities seeking to sell electricity
28      pursuant to the mandatory purchase obligation provisions of PURPA. The
29      criteria must ensure that: (1) the thermal energy output of the new qualifying
30      cogeneration facility is used productively and beneficially; (2) the electrical,
31      thermal, and chemical output of the cogeneration facility is used
32      fundamentally for industrial, commercial, or institutional purposes and not for
33      the sale to an electric utility; and (3) progress toward the development of
34      efficient electric generating technology continues.


                                           4-5
 1          The existing criteria for qualifying cogeneration facilities will continue to
 2      apply to QFs existing on the date of enactment or that have filed a notice of
 3      self-certification, self-recertification, or an application for certification prior to
 4      the date on which the FERC issues its final rule revising the criteria for new
 5      qualifying cogeneration facilities. Until the new regulations are adopted, a
 6      new cogeneration facility would be unable to determine whether it will meet
 7      FERC’s QF criteria.
 8          In light of these PURPA amendments, the Commission should require
 9      the utilities to enter into only one-year agreements at market rates and
10      should require QFs to participate in competitive solicitations to obtain new
11      long-term agreements at the same rates and terms available to non-QF
12      generators. The Commission should take no action that will result in
13      additional above-market payments to QFs, particularly given the present
14      uncertainties regarding whether the utilities will continue to be obligated to
15      enter into new QF contracts.

16   3. Competitive Solicitations for Firm Power Products Are an
17      Appropriate Means to Implement PURPA in Today’s Deregulated
18      Market
19          PG&E proposes to provide QFs with expiring contracts and new QFs
20      opportunities to bid for short-term, intermediate, and long-term contracts in
21      PG&E’s all-source and renewable solicitations. In addition, while the utility’s
22      obligation to enter into new agreements under PURPA remains, PG&E
23      proposes to offer QFs one-year PPAs at market prices. Lastly, PG&E
24      welcomes opportunities to renegotiate or restructure QF contracts at market
25      prices and terms.
26          Since PURPA was enacted in 1978, the wholesale power market has
27      been significantly restructured. Today, PG&E’s primary methods to acquire
28      new resources is competitive solicitations for mid-term and long-term
29      contracts and day-ahead, hour-ahead and real-time short-term purchases.
30      The transformation of the California market is the result of many federal and
31      state laws and regulations meant to reduce consumer rates and increase
32      consumer choice by creating and cultivating competitive markets for
33      wholesale power. Among the most significant are:



                                             4-6
 1   •   The Energy Policy Act of 1992 established a new category of
 2       independent producers, Exempt Wholesale Generators (EWGs), with
 3       rights to sell into the wholesale electricity market;

 4   •   FERC Order 888 (61 F.R. 21540 (May 10, 1996) FERC Statutes and
 5       Regulations, Regulation Preambles 1991-1996 ¶ 31,036 (1996))
 6       required utilities to offer open, non-discriminatory access to their
 7       transmission systems to non-utility market participants;

 8   •   FERC licensed non-utility power marketers to buy and sell power in the
 9       wholesale market at market-based rates;

10   •   Assembly Bill (AB) 1890 required California utilities to divest a large
11       share of their generating assets to expand the independent wholesale
12       market and enacted direct access to allow suppliers to sell directly to
13       retail customers;

14   •   California established the California Independent System Operator
15       (CAISO) to promote a broad and deep wholesale market and guarantee
16       all suppliers equal access to the grid;

17   •   A trading market has evolved, with numerous entities buying and selling
18       large quantities of power at transparent prices every day. Daily indices
19       that meet FERC standards for liquidity and accuracy, such as the ICE
20       Daily Index and Dow Jones Daily Index, perform the same price
21       transparency function for power transactions that gas indices perform for
22       the gas market;

23   •   Technological advances have led to production efficiency improvements
24       and improved emissions reduction technologies; and

25   •   Financial instruments and innovative market products such as capacity
26       call options, fixed-for-floating electricity and gas swaps, and put options,
27       have been developed to better match seller capabilities with buyer
28       needs.

29       These changes successfully introduced competition into what had been
30   a vertically integrated utility regime. Utilities now are neither monopoly
31   power suppliers nor buyers; hundreds of independent suppliers across the
32   country now participate in active wholesale and retail markets. QFs are but

                                       4-7
 1      one category of an array of wholesale suppliers—including EWGs, power
 2      marketers, power marketing agencies, and other wholesale entities—who
 3      compete to sell power to utilities, energy service providers, and retail
 4      customers. Independent power suppliers, including QFs, have broad rights
 5      to sell power throughout the region—rights that did not exist when the
 6      standard offer agreements were executed. QFs now have the ability to:
 7      •   Be licensed by FERC to sell power at market-based rates;

 8      •   Have rights to transmission capacity equal to those of utilities; and

 9      •   Sell to wholesale or retail customers.

10          Given that many suppliers now compete to sell power to utilities, and
11      that suppliers—including QFs—have many potential buyers, moving QFs to
12      market-based pricing and terms is clearly appropriate. Since California’s
13      utilities have divested a large share of their generation and now buy more
14      power than they generate, market-based pricing and terms are what the
15      utilities avoid when purchasing QF power.

16   4. PG&E’s Competitive Solicitations
17          PG&E proposes that QFs to bid to fill PG&E’s net open position in its
18      renewable and all-source competitive solicitations. In 2004, PG&E secured
19      66 percent of its energy needs from wholesale power suppliers: 42 percent
20      directly from suppliers and 24 percent through contracts between CDWR
21      and wholesale suppliers. PG&E’s competitive solicitations are explained in
22      detail below in the testimony of Mr. La Flash.
23          The prices paid to winning bidders in such solicitations represent
24      PG&E’s actual avoided costs. Compared to “standard offers,” these
25      solicitations will achieve a more reliable and economical resource base and
26      will allow PG&E to procure only the amount of power needed.
27          PG&E’s proposal that new QFs and QFs with expiring contracts
28      participate in competitive all-source solicitations is fully consistent with
29      Decision 04-12-048 (the 2004 Long-Term Plan (LTP) decision). In the LTP
30      Decision, the Commission acknowledged there is a hybrid power market in
31      California and “we continue to . . . advance the positive benefits of
32      competition, and deliver California’s energy services according to the



                                           4-8
 1          priorities of state policy.” (D.04-12-048, mimeo at pp. 110, emphasis
 2          added.)
 3              The Commission’s criteria for all-source solicitations should apply
 4          equally to new and expiring QFs’ participation in future electric procurement.
 5          QF participation in this process will ensure bids that are “market-tested” and
 6          prices equal to the IOUs’ avoided costs within the meaning of PURPA. Such
 7          a process will ensure the benefits of competition accrue to PG&E’s
 8          customers and minimize the risk of over-subscribing to long-term,
 9          over-priced contracts. PG&E’s proposal for new long-term firm capacity QF
10          contracts also is consistent with Decision 04-01-050, which requires the
11          utilities to enter long-term QF contracts with new QFs either through
12          competitive bidding or negotiation.[5]
13              Existing QFs have numerous competitive advantages over new
14          generation:
15          •   Capital is paid for;

16          •   Cogeneration has operating efficiencies in combination with on-site
17              industrial processes; and

18          •   Cogeneration has the ability to sell steam as a second revenue source
19              to spread its fixed costs and lower its fuel chargeable to power.

20              Renewable QFs have the advantage that the California utilities have a
21          20 percent RPS mandate. California IOUs count existing renewable QFs in
22          their RPS portfolio, and are motivated to continue buying power from these
23          QFs. Thus, renewable QFs have the benefit of selling to a dedicated
24          market. Additionally, renewable QFs have unique advantages that will
25          enable them to compete with conventional generation for utility PPAs:
26          •   Many new, repowered, or existing renewable QFs, including those
27              fueled by wind, geothermal, and biomass, are eligible for federal
28              production tax credits, investment tax credits, and accelerated
29              depreciation benefits;

30          •   Renewable QFs are not subject to the greenhouse gas evaluation adder
31              ordered in Decision 04-12-048; and


     [5]   D.04-01-050, mimeo at p. 160.

                                             4-9
 1            •   Existing renewable facilities can qualify for subsidies of up to
 2                one cent/kWh from the Existing Renewables Resource program initially
 3                established with Senate Bill (SB) 90 and continued through SB 1038.

 4                Thus, both conventional and renewable QFs will have ample opportunity
 5            to sell their power to PG&E—and have advantages that should make them
 6            quite competitive.

 7         5. PG&E Proposes to Continue Bilateral Negotiations
 8                PG&E routinely seeks to renegotiate existing QF power purchase
 9            agreements to retain these resources in its generating portfolio and meet
10            resource adequacy requirements. For example, in 2003 and 2004, PG&E
11            renegotiated five contracts with facilities originally constructed as QFs:
12            three with biomass facilities and two with repowered wind facilities. The new
13            PPAs are at market rates, and contain modern performance, scheduling,
14            and credit provisions. PG&E will continue to look for similar opportunities to
15            retain existing renewable and conventional QF generation.

16         6. PG&E’s Short-Term Contract Option
17                PG&E proposes that any QF located in its service territory and not under
18            an existing PPA may sell energy to PG&E at market-based prices under a
19            one-year PPA based on the EEI Master Agreement.[6] These PPAs could
20            be renewed annually through 2014 at the QF’s option (so long as the
21            PURPA obligation remains), at then-applicable market prices and with any
22            modifications appropriate to meet changing circumstances, such as
23            resource adequacy standards.
24                PG&E proposes two PPA options for QFs: a unit-firm product and an
25            as-delivered product.[7] Under either agreement, PG&E proposes that QFs
26            one megawatt or greater serve as their own scheduling coordinators as this


     [6]     See PG&E Prepared LTP Testimony, July 9, 2004, Chapter 4,
             Section J.2a.(2) (R.04-04-003).
     [7]     PG&E has further refined its proposals for one-year contracts and withdraws
             the proposed contract filed as Exhibit A to PG&E’s Response to
             Administrative Law Judge’s Ruling Requesting Proposals and Comments on
             the Development of a Long-Term Policy for Expiring Qualifying Facility
             Contracts, dated November 10, 2004. Once the Commission has made a
             decision in this proceeding, PG&E will file draft agreements which comply with
             the Commission’s decision.

                                               4-10
1          is not an expense that PG&E bears for non-QF generation and is therefore
2          not a PG&E avoided cost.
3             The EEI Master Agreement is widely recognized in the industry and has
4          been approved by the Commission for use in the RPS proceeding.[8] Using
5          the EEI Master for QF power purchase would make QF contracts consistent
6          with those of other wholesale suppliers and eliminate the contract provision
7          advantages QFs have over their non-QF competitors. Table 4-3 lists the
8          major provisions that would be included in such contracts and compares
9          them to the terms of the SO1 PPA.




    [8]   D.04-06-014.

                                           4-11
1                                              TABLE 4-3
2                                 PACIFIC GAS AND ELECTRIC COMPANY
3                            COMPARISON OF PROPOSED ONE-YEAR CONTRACTS
4                                    WITH EXISTING SO1 CONTRACTS


    Line                        Proposed One-Year Unit-        Proposed One-Year As-
    No.       Provision              Firm Capacity                Delivered Energy         Existing SO1
     1     Energy Price        Each hour,50 Percent ICE      Each hour, 50 Percent ICE   SRAC Energy
                                and 50 Percent Dow            and 50 Percent Dow Jones    Formula
                                Jones Day-Ahead NP 15         Day-Ahead NP 15
                                On-Peak and Off-Peak          On-Peak and Off-Peak
                                Index                         Index
     2     Capacity Price      Avoided RA compliance         Avoided RA compliance       $66.43/kW-yr
            for qualifying       costs                         costs
            RA capacity
            only
     3     Daily               Standard ISO Timetables       Standard ISO Timetables     None
            Scheduling           and Protocols for             and Protocols for
                                 Day-Ahead Schedules           Day-Ahead Schedules for
                                                               QFs > 1 Mw
     4     Forecasting         Weekly, Monthly and           Weekly, Monthly and         None
                                Annual Forecasts               Annual Forecasts
     5     Deliveries          SC-SC Trade                   SC-SC Trade for QFs >       None. Utility is
                                                               1 Mw                      now the SC
     6     Emergency           Standard ISO Emergency        Standard ISO Emergency      None
             Response            Response Provisions           Response Provisions
     7     Performance         Penalties to Capacity         Day-Ahead scheduling        None
             Requirement         Payment for Failure to
           s                     Deliver 95% during on-
                                 peak months and 90%
                                 during off-peak months
                                 (not counting scheduled
                                 outages)
     8     Credit              None                          None                        None
     9     Termination         One-Year Commitment.          One- Year Commitment.       QF has the
            Rights               Ability to terminate if      Ability to terminate if    unilateral right to
                                 selected in a PG&E           selected in a PG&E         terminate on
                                 Solicitation                 Solicitation               30-Day Notice


5             a.   Energy Price for Short-Term Purchases in Proposed Agreements
6                         Because PG&E avoids purchases from the market when buying
7                  short-term QF power, PG&E proposes the energy price to be paid under
8                  these one-year contracts be the average of two transparent market
9                  indices for sales at NP-15:[9]


     [9]     PG&E originally proposed short-term pricing based on data from the Dow
             Jones Daily Index. PG&E continued examining which indices were most
             appropriate for our proposed one-year contracts since submitting its proposal
             in November 2004. PG&E now recommends using a combination of the ICE
             and Dow Jones indices to insure a robust pricing methodology. Deliveries
             outside of NP-15, such as ZP-26, would be adjusted to reflect the difference
             in market value from NP15.

                                                      4-12
 1                 (1) ICE Daily Index for day-ahead on-peak and day-ahead off-peak
 2                     NP15 deliveries; and
 3                 (2) Dow Jones Daily Index for day-ahead on-peak and day-ahead
 4                     off-peak NP15 deliveries.
 5                     As the Commission has recognized, the utilities purchase power in
 6                 the spot market to meet their net short positions.[10]
 7                     In Chapter 3, Dr. Fox-Penner testifies to the liquidity, accuracy, and
 8                 transparency of the ICE and Dow Jones energy market indices.[11]
 9             b. RA Capacity Contract Option
10                     PG&E’s proposed unit-firm EEI Master and confirm would make a
11                 short-run Resource Adequacy (RA) capacity payment available to those
12                 QFs that offer capacity that meets the RA requirements and helps
13                 PG&E avoid the cost of complying with RA requirements. The RA
14                 capacity pricing method is explained in Dr. Strauss’s testimony,
15                 Chapter 3, Section E. In this case, no separate payment for capacity
16                 would be appropriate under PURPA because the utility has no avoided
17                 cost attributable to unneeded RA capacity.
18                     PG&E’s proposals offer a buyer for QF power at market rates that
19                 are just and reasonable for utility customers and QFs. As both the
20                 Commission and FERC have recognized, it is now appropriate to set QF
21                 prices at market rates.[12]

22          7. PG&E’s QF Contracts Expire Gradually Over the Next 10 Years
23                 The volume of QF deliveries from facilities whose PPAs expire during
24             the next 10 years is modest compared to the size of PG&E’s overall
25             resource portfolio. Table 4-4 details the number of QF PPAs expiring from
26             2006 to 2014 (contracts expiring before 2006 have been granted five-year
27             SO1 extensions by Decision 04-01-050; these extensions expire in 2009).
28             Table 4-4 also shows the projected annual GWhs of power these QFs
29             produce and their associated percentage of PG&E’s total energy sales.



     [10]     D.01-03-067, mimeo at p. 12.
     [11]     See Chapter 3, Section C.4.
     [12]     See e.g., D.01-03-067, mimeo at p. 22 and Southern California Edison Co.,
              70 FERC ¶ 61,215 (1995).

                                               4-13
 1            These expiring PPAs represent an average of approximately 1.1 percent per
 2            year of PG&E’s annual total energy deliveries. Given the gradual expiration
 3            of PG&E’s QF contracts over the next 10 years, it is an ideal time for the
 4            Commission to institute a market-based program for QFs. The Commission
 5            can initiate such a program without any danger of resource scarcity.

 6                                           TABLE 4-4
 7                              PACIFIC GAS AND ELECTRIC COMPANY
 8                          EXPIRING QFS AND PROJECTED ANNUAL GWHS


                                                            Average MW
                         No. QF     Energy Deliveries      Deliveries From     Expiring QF PPA Energy
     Line                 PPAs      From Expiring QF      Expiring QF PPAs     Deliveries as percent of
     No.       Year      Expiring     PPAs (GWh)               (MW)(a)          PG&E Retail Sales(b)
       1     2006           4                52                      6                   0.1%
       2     2007          10               988                    113                   1.2%
       3     2008           4               545                     62                   0.6%
       4     2009          33             3,163                    361                   3.7%
       5     2010          11               879                    100                   1.0%
       6     2011           3               950                    108                   1.1%
       7     2012           8               846                     97                   0.9%
       8     2013          11               992                    113                   1.1%
       9     2014          11               715                     82                   0.8%
       10    Total          95             9,130                   1,042                  10.0%
     ______________
     (a) Average Megawatt Deliveries equals Annual Energy Deliveries *1,000 MW/GW, divided by
          8,760 hours per year.
     (b) Using PG&E Total Retail Sales from Table 3-2 Reference Case (GWh) R.04-04-003, PG&E
          Prepared LTP testimony, July 9, 2004. The 10.0 percent total reflects Total Annual GWh from
          expiring QFs as a percent of PG&E’s Total Retail Sales in 2014.


 9         8. PG&E’s Proposal Furthers the Commission’s Policy Objectives
10            a.    PG&E’s Proposal Reduces the Likelihood of Additional Stranded
11                  Costs From Future QF Contracts
12                      PG&E’s proposal is consistent with the Commission’s recent policy
13                  statements on resource planning. In Decision 04-12-048, the
14                  Commission set forth standards for utility procurement during the next
15                  10 years. As the Commission discussed, the utilities might be acquiring
16                  capacity that is not ultimately needed due to departing load. The
17                  Commission stated: “As the utilities will be acquiring their new resource
18                  needs through the competitive and transparent procurement process
19                  that we are adopting, it is our expectation that there should be little if any


                                                   4-14
 1        stranded costs.” (D.04-12-048, mimeo at p. 54.) PG&E’s proposal
 2        would pay market prices for QFs, which, as the Commission stated,
 3        should minimize the need to apportion any QF costs arising from new
 4        contracts or contract extensions to departing load. Stemming the
 5        growth of stranded cost is extremely important as Community Choice
 6        Aggregation, renewal of Direct Access, and increased pressure of
 7        municipalization threaten to leave a dwindling base of bundled
 8        customers burdened with above-market costs. Under PG&E’s proposal,
 9        it will only purchase power in its competitive solicitations to meet its net
10        short, or purchase short-term power at market prices it can resell, if
11        need be, without a significant loss.
12   b. PG&E’s Proposal Supports the RPS Program
13            PG&E’s proposal also advances this Commission’s order to
14        “procure the maximum amount of renewable generation resources via
15        all-source Request for Offers…” (Ordering Paragraph 3.) The QFs’
16        proposal to require standard offers to be available irrespective of the
17        utility’s resource needs, and to require mandatory increases in
18        purchases from cogenerators would require the utilities to give
19        preference to gas-fired cogenerators and would crowd out procurement
20        of renewables, which are primarily baseload or intermittent technologies.
21        In addition, simply extending the contracts of renewable QFs at prices
22        much higher than those being offered under the RPS program would
23        undermine the competitive procurement mandate of the RPS program.
24            The EAP loading order prioritizes resources that emphasize energy
25        conservation and favors renewables over fossil-fueled resources. The
26        QF proposals would impose a place for fossil-fueled cogenerators built
27        with 1980s technology in the EAP loading order. Since they are not
28        renewable technology, they do not belong in the loading order.
29   c.   PG&E’s Proposal Furthers Least Cost – Best Fit Procurement
30            The Commission recently “adopted the policy of [Least Cost Best
31        Fit] LCBF which dictates that the IOUs obtain the best and most cost
32        effective products for their customers.” (D.04-12-048, mimeo at p. 144.)
33        PG&E seeks to integrate the QFs into the utility procurement process by
34        including QFs in all-source solicitations. This would further the

                                       4-15
 1                 Commission’s goals of selecting the most efficient resources for
 2                 customers. The QFs, by contrast, seek mandatory baseload purchase
 3                 obligations—whether the utility needs the power or not—at
 4                 administratively set prices that have not been market-tested. This
 5                 proposal, if adopted, would require the utilities to purchase unneeded,
 6                 more expensive QF power that may not be the best fit for electric
 7                 customers.
 8             d. PG&E’s Proposal Supports Resource Adequacy Standards
 9                     PG&E proposes a one-year unit firm contract under which PG&E
10                 would pay a Resource Adequacy (RA) capacity price for QF contracts
11                 that help PG&E meet RA requirements. The RA requirements are still
12                 under deliberation in Rulemaking 04-04-003 but they will most likely
13                 require delivery during peak times.
14                     PG&E proposes to modify the one-year unit-firm contract to conform
15                 to the RA provisions if the decision is issued after the final decision in
16                 this proceeding. Under PG&E’s proposal, the performance provisions of
17                 the new short-term QF contracts will insure system reliability in contrast
18                 to current SO1 contracts, under which the QF has no performance
19                 requirements and a unilateral right to terminate the contract.

20   B. Implementation of PURPA in Other States (Lauckhart)
21          1. Introduction and Summary
22                 PG&E engaged Global Energy Advisors (“Global Energy”) to perform
23             nationwide research to determine how other states are determining QF
24             avoided cost rates. PG&E asked Global Energy to investigate how avoided
25             costs are determined for QFs larger than 1 MW and to differentiate between
26             methodologies for long-term and short-term purchases.
27                  We found the implementation of PURPA often varies not only from state
28             to state, but from utility to utility within a given state.[13] Our research has
29             determined that at least 21 states, with approximately 35 percent of the QF
30             MWs constructed in this country, now use competitive bidding to establish



     [13]     In the survey, where a state regulatory body has treated utilities in the state
              differently, Global Energy has generally classified the treatment of the largest
              utility as the treatment for the state.

                                                4-16
 1             market based QF prices.[14] Two states not on this list, New York and
 2             Louisiana, with approximately 33 percent of QF MWs, rely on negotiated
 3             contracts to establish market based QF prices.[15] As a result, more than
 4             two-thirds of the states rely on the “market” to determine prices for QF
 5             contracts. Fewer than ten states explicitly use administratively-determined
 6             avoided costs.[16] Excluding California, which comprises 14 percent of the
 7             nationwide QFs, the states currently explicitly using administratively-
 8             determined avoided cost have only approximately 2 percent of the QF MWs
 9             that exist today. The remaining states generally appear to rely on bilateral
10             negotiations between utilities and QFs to establish avoided costs, which we
11             characterize as market determined avoided cost states.

12          2. Research Regarding Other States’ Implementation of PURPA
13             a.   Overview
14                      To conduct our research, we first telephoned a representative of
15                  each state’s regulatory agency with jurisdiction over electric utilities
16                  operating in the state (PUCs).[17] We had detailed discussions with
17                  PUC staff to determine how utilities contracted with QFs, methodologies
18                  used to determine avoided costs, and how short-term energy and
19                  long-term power purchases from QFs were conducted. We also
20                  researched state laws, regulations, and regulatory orders.
21                      If we determined that additional information was needed beyond the
22                  telephone contact and a search of relevant state data bases, we


     [14]     This number includes states in New England who have instituted a Direct
              Access regime, with the local utility serving as the default provider and energy
              and capacity for default service supplied by competitive solicitations.
     [15]     For our purpose, we define avoided cost as being “market” determined if such
              prices are determined by competitive bidding, individual contract negotiation,
              or both. We also define avoided cost as being “market” determined if the
              avoided cost is determined through use of a market index or an economic
              dispatch model (which model is designed to perform hourly calculations using
              actual hourly heat rates, actual hourly gas prices, and actual hourly spot
              electricity prices) since all the key parameters are actual market values.
     [16]     Administratively-determined avoided costs involve forecasting prices for some
              period in the future and then making these prices available to Qualifying
              Facilities.
     [17]     Global Energy was able to communicate with representatives of
              approximately 40 states, including all the states with the highest amounts of
              non-utility generation.

                                                 4-17
 1               researched one or more utilities under the PUC jurisdiction in that
 2               particular state, both by telephone and by a review of utility tariff rates
 3               posted on utility and PUC websites. Global Energy performed a utility
 4               specific research when: (1) the PUC indicated that utilities published
 5               administered tariff rates for QFs 1 MW and larger; (2) the PUC indicated
 6               that the state left the interpretation of PURPA up to the utilities; or
 7               (3) Global Energy determined additional, useful information might be
 8               available from specific utilities.
 9                   We identified three general means by which long-term avoided costs
10               are determined: (1) competitive solicitations; (2) published tariff rates;
11               and (3) bilateral contract negotiations.
12                   We also identified four general approaches to the treatment of
13               “as-delivered” power where a QF does not qualify for a long-term
14               contract: (1) no contract is available to that QF (the utility instead is
15               required to wheel the power to other potential purchasers); (2) the utility
16               must purchase the power at an administratively-determined energy
17               avoided cost; (3) the utility must purchase the “as-delivered” power at
18               market index prices (e.g., the California Oregon Border index published
19               by Dow Jones); or (4) the utility must negotiate a contract rate for
20               “as-delivered” power. We found that only California mandates separate
21               capacity payments for as-delivered power. Although it was difficult in
22               some cases to categorize a state’s avoided cost methodology, we have
23               attempted to reflect the general approach used in each state below.
24           b. States Using Solicitations to Determine Avoided Cost Rates
25                   Twenty-one states have a competitive solicitation process to
26               establish avoided costs either alone or in connection with bilateral
27               negotiations for new agreements.[18] Table 4-5, below, identifies these
28               states.




     [18]   In 1993, FERC stated that 30 states use competitive bidding (i.e., either the
            state has adopted provisions for utilities to use bidding or the state at least
            permits utilities to use bidding). (Cogeneration; Small Power Production
            et al., 64 FERC ¶ 61, 369, p. 63, 491 (1993).)

                                                4-18
 1                                        TABLE 4-5
 2                           PACIFIC GAS AND ELECTRIC COMPANY
 3                           STATES USING COMPETITIVE BIDDING



               Colorado                              New Hampshire
               Connecticut                           New Jersey
               Delaware                              New York
               Florida                               North Carolina
               Kansas                                Ohio
               Maine                                 Pennsylvania
               Maryland                              Rhode Island
               Massachusetts                         Virginia
               Minnesota                             Washington
               Montana                               Wyoming
               Nevada


 4                   In general, these states use all-source competitive solicitations to
 5               identify the supplies that meet the utilities’ resource needs in a least-cost
 6               fashion.[19] In these states, QFs bid in solicitations against other
 7               non-QF power producers. If the QF’s bid is not accepted, then the QF
 8               price is, by definition, above the particular utility’s avoided cost. These
 9               states have approximately 35 percent of the QF power produced in this
10               country.
11                  The table below lists the states with the most QF activity as
12               measured by the number of MW identified as QF.[20] It appears from
13               our research that 82 percent of the QF power in the United States is
14               located in 12 states. As noted below, 9 of the 12 states with the most
15               QF power rely on the market (e.g., through competitive bidding and/or
16               bilateral negotiations) to establish avoided cost rates. Accordingly, the



     [19]   An RFP used to determine QF avoided cost payments must reflect all
            technologies for meeting resource needs as well as all types of providers
            (e.g., IPPs, utility purchases, EWGs, QFs, etc). (Southern California Edison
            Company, 70 FERC ¶ 61, 215, p. 61, 677 (1995).)
     [20]   This data was compiled from EIA-860 filings by generation plant owners
            made in early 2004 for plants in 2003.

                                              4-19
 1              states where more than half of the QF power is located now rely on the
 2              market to establish QF rates.

 3                                       TABLE 4-6
 4                          PACIFIC GAS AND ELECTRIC COMPANY
 5                        STATES WITH THE MOST QF POWER (IN MW)




               State                 MW               Percent                Method
               Texas               12799                 26%                  Market

           California               6656                 14%

           New York                 3721                 8%                   Market

           Louisiana                3314                 7%                   Market

              Florida               2704                 6%                   Market

              Michigan              2578                 5%              Direct Access(a)

          New Jersey                1734                 4%                   Market

              Virginia              1661                 3%                   Market

        North Carolina              1245                 3%                   Market

        Massachusetts               1169                 2%                   Market

         Pennsylvania               1075                 2%                   Market

               Maine                 883                 2%                   Market

     Total                         39539
     _______________
     (a) Michigan is moving to “customer choice” direct access. Its approach to avoided cost
         is unclear. Most of the QF MW in Michigan is made up of a 1980’s vintage 35-year
         QF contract (the 1,400 MW Midland Cogeneration contract at Dow Chemical/Dow
         Corning).
         Total of all 50 States     48935



 6       c.     FERC Decisions Regarding QF Solicitations
 7                   PG&E’s proposals seeks to require QFs seeking long-term power
 8              purchase agreements to participate in PG&E’s all-source or renewable
 9              solicitations to obtain agreements at PG&E’s true avoided cost. FERC
10              has approved of all-source solicitations as a means for a utility to meet
11              PURPA purchase requirements.


                                              4-20
 1                   As early as 1988, FERC clearly recognized that competitive
 2               wholesale markets provided not only a valid but an essential benchmark
 3               for measuring avoided costs. In that year, FERC proposed to adopt
 4               regulations that would authorize state regulatory authorities and
 5               nonregulated electric utilities to implement bidding procedures as a
 6               means of establishing rates for power purchases from qualifying
 7               facilities (QFs) under Section 210 of PURPA.[21] The purpose of this
 8               proposed rule was to permit bidding programs that would accurately
 9               establish utilities’ avoided cost. FERC believed that bidding would
10               promote the statutory objectives of PURPA by encouraging
11               cogeneration and small power production, energy conservation, efficient
12               use of facilities and resources by electric utilities and equitable rates for
13               electric consumers.
14                   FERC ultimately did not adopt its proposed bidding regulations, but
15               not because FERC altered its opinion that a bidding program was an
16               appropriate process for determining a utility’s avoided cost consistent
17               with PURPA’s requirements. On the contrary, because the use of
18               bidding had become so prevalent by 1993, FERC determined its
19               proposed regulations were unnecessary. In its Order Terminating
20               Proceedings, FERC observed:
21                   In addition to the Commission’s case-by-case experience regarding
22                   regulation of non-traditional power producers, including
23                   [Independent Power Producers], substantial experience has been
24                   gained by state regulatory commissions and utilities themselves
25                   regarding non-traditional power producers and competitive bidding.
26                   At the time of the Bidding NOPR only a few states had taken steps
27                   to allow competitive bidding. Now 30 states use competitive bidding
28                   (i.e., either the state has adopted provisions for utilities to use
29                   bidding or the state at least permits utilities to use bidding).
30                   Compare Bidding NOPR, FERC Statutes and Regulations at
31                   p. 32,025 with 4 Robertson’s Current Competition No. 3 at p. 16
32                   (August 1993). Thus, both state regulatory commissions and
33                   utilities appear to be making substantial progress without the need
34                   for additional Commission guidance.[22]




     [21]   Regulations Governing Bidding Programs, 53 F.R. 9324 (Mar. 22, 1988),
            FERC Statutes and Regulations, ¶ 32, 455, p. 32, 021 (1988).
     [22]   Order Terminating Proceedings, 64 FERC ¶ 61, 364, p. 63, 491 (1993)
            (emphasis added).

                                               4-21
 1                  Thus, FERC supports competitive solicitations as a means of
 2              determining a utility’s avoided costs. FERC’s support appears to have
 3              encouraged many states to adopt a market-based approach to
 4              establishing QF rates.
 5                  Below, I discuss the solicitation processes used in states with a
 6              significant amount of QF power, including Texas, New York, Louisiana
 7              and Florida to determine if PG&E’s proposals in this proceeding are
 8              consistent. I also discuss the state of Washington’s implementation of
 9              PURPA through competitive solicitations because I believe it is
10              instructive here.
11              (1) Texas
12                      More than one quarter of the QF power built in this country
13                  today is located in Texas, with nearly 13,000 MW serving
14                  approximately 22 percent of the state’s power needs. Pursuant to
15                  Texas Senate Bill 7 (SB 7), Texas electric utilities were required, by
16                  January 1, 2002, to restructure themselves into holding companies,
17                  each having three required subsidiary companies: a generating
18                  company, a transmission and distribution company, and a retail
19                  electric service provider. In 2001, Texas QFs, owning
20                  approximately 7,500 MW of QF power sold to three investor-owned
21                  utilities (IOUs), filed with FERC a petition for declaratory order that
22                  confirm that restructured electric utility purchasers of their output in
23                  Texas would continue to have a purchase obligation under
24                  PURPA.[23] The price paid for energy was calculated at the time
25                  using the non-firm avoided cost pricing methodologies included in
26                  tariffs approved by the Texas PUC. These QFs were advised by the
27                  Texas IOUs that starting in 2002 the Texas ISO would provide a
28                  sufficient market for the QF output and they would no longer
29                  purchase QF power.
30                      The Texas PUC, in response to the QFs’ filing, filed a notice of
31                  intervention and a separate request that FERC waive the obligation
32                  of Texas IOUs to purchase from QFs, arguing that the PURPA


     [23]   FERC Docket No. EL01-49-000.

                                             4-22
 1                  obligation is unnecessary following the Texas restructuring and such
 2                  obligation would impede the functioning of a competitive market.[24]
 3                  FERC agreed with the Texas QFs that PURPA still required utilities
 4                  to purchase their power (even after restructuring in Texas) and
 5                  denied the Texas PUC request for a waiver. In that Order, FERC
 6                  stated “our review of the Texas Commission’s petition indicates that
 7                  its major concern is with an avoided cost rate in the face of retail
 8                  competition. The Texas Commission suggests that its current,
 9                  administratively determined avoided costs will not be accurate, and
10                  may inhibit the free market. We share the Texas Commission’s
11                  concern that the mandatory QF purchase obligation under PURPA
12                  in conjunction with administratively avoided cost rates may be
13                  inconsistent with the operation of an effective competitive market.
14                  Nevertheless, under these circumstances, rather than the approach
15                  advocated here, we believe the Texas Commission has sufficient
16                  flexibility to adopt a more market-oriented method of determining
17                  avoided costs which would be both consistent with PURPA and its
18                  retail competition program.”[25]
19                      The Texas PUC thereafter opened a rulemaking regarding QF
20                  sales to electric utilities.[26] Following numerous comments and
21                  reply comments, on June 6, 2002, the Texas PUC issued an Order
22                  Adopting Amendments to its QF regulations.[27] The new QF
23                  regulations allow bilateral negotiation of rates. The regulations also
24                  require the IOUs to purchase from QFs at rates not to exceed
25                  avoided costs. The rules state: “Rates for purchase shall be based
26                  upon a market-based determination of avoided cost over the specific
27                  term of the contract…” For QFs that agree to commit, on a day-


     [24]   FERC Docket No. EL01-6000.
     [25]   Order Granting Declaratory Order and Denying Waiver of Regulations
            Implementing PURPA in Dockets EL01-49-000 and EL01-60-000, 95 FERC ¶
            61,243, 61,8382001 (emphasis added).
     [26]   Rulemaking Concerning Arrangements Between Qualifying Facilities and
            Electric Utilities, Texas PUC Project No. 24365.
     [27]   Order Adopting Amendments to §25.242 as Approved at the June 6, 2002
            Open Meeting, Texas PUC Project No. 24365 (June 20, 2002).

                                             4-23
 1                  ahead basis, to deliver firm power for the next day, the QF purchase
 2                  rates are based on prices for the day that the power was actually
 3                  delivered as reported or published in an independent third party
 4                  index or survey of trades of commonly traded power products in
 5                  ERCOT. The rules also provide for methodologies for purchases of
 6                  non-firm (as-delivered) QF power. The methodology requires hourly
 7                  calculations for the hours when power is delivered, taking into
 8                  account decremental energy that would have been incurred by the
 9                  IOU if the QF were not operating. The Texas PUC rules also allow
10                  QFs to compete with all other suppliers to sell power to whomever
11                  they can successfully negotiate with.
12               (2) New York
13                      In 1980, the New York legislature, consistent with PURPA,
14                  required that the New York Public Service Commission (PUC) was
15                  to require state-regulated electric utilities to purchase power from
16                  QFs. The PUC was charged with overseeing the process and
17                  establishing power purchase rates. In 1981, the legislature modified
18                  these requirements to require the PUC to establish a minimum PPA
19                  price of at least 6 cents/kWh for purchases from QFs. This 1981
20                  requirement became commonly referred to as the “Six-Cent Law.”
21                  In 1992, the New York legislature amended its requirements by
22                  repealing the Six-Cent Law. In the intervening years between 1981
23                  and 1992, numerous QF contracts were signed and average retail
24                  electric rates increased by 25 percent. As indicated above, the
25                  “Six-Cent Law” was abolished in 1992.
26                      The PUC initiated several proceedings to review long-run
27                  avoided cost estimation policies and methods. In 1998, the PUC
28                  noted “no QF contracts have been entered into at [Long Run
29                  Avoided Cost] LRAC estimates since the early 1990s, and
30                  maintaining the estimates for this purpose is not required.”[28]
31                  However, QFs with existing contracts (including those which did not



     [28]   State of New York, Public Service Commission Order Closing
            Proceeding 93-E-0175, November 10, 1998.

                                            4-24
 1                  have the protection of the 6 cent/kWh floor) continued to require
 2                  calculation of avoided cost. Further, the PUC needed to establish a
 3                  methodology to determine rates for new QFs. For some time during
 4                  the 1990s, the avoided energy costs were calculated using
 5                  computer-based simulation models. Debates over the model inputs
 6                  and methods were very important because of the large amount of
 7                  power under contract with prices based on the modeling. In 1996,
 8                  the PUC noted: “With the advent of competition, both side’s
 9                  arguments have become tangential to the increasingly compelling
10                  principle that avoided costs should not be determined on the basis
11                  of econometric proxies and administrative rulings, if the market itself
12                  can make the same determinations more efficiently without
13                  regulatory intervention.”[29]
14                      Over the ensuing years, the methodology used in New York has
15                  evolved. According to PUC staff, all jurisdictional utilities in
16                  New York currently have a QF tariff with energy-only rates for QFs
17                  that cannot guarantee a capacity delivery. The energy price is the
18                  real-time locational marginal energy price at the plant bus (for the
19                  each hour when the QF power is delivered) as determined by the
20                  NYISO. If the QF can guarantee a specific amount of capacity, then
21                  the QF will also receive a capacity payment with price based on the
22                  respective six-month block auction conducted by the NYISO.
23                  Further, a QF who desires a long-term contract may negotiate a
24                  Contract with a utility.
25               (3) Louisiana
26                      In 1981 and 1982, the Louisiana Public Service Commission
27                  (PUC) adopted rules for the purchase of electric energy from QFs in
28                  accordance with PURPA. Contracts for “as-delivered” energy were
29                  signed under these rules. Prices paid under these contracts were
30                  determined by running a dispatch model. First the dispatch model is
31                  run with QF output included. Then the load is increased by the QF



     [29]   State of New York, Public Service Commission Order Closing
            Proceedings 93-E-0912 and 93-E-1075, July 15, 1996.

                                               4-25
 1                   output. This represented how much the system load would increase
 2                   if the QFs were not generating. The difference in the cost between
 3                   the two dispatch runs is determined as the avoided cost. The
 4                   calculation was performed for each hour and the hourly values are
 5                   accumulated for the month and applied to the hourly output of each
 6                   QF resulting in the total monthly payment.
 7                       In March 1995, Calciner Industries, Inc. (“Calciner”) filed a
 8                   petition with the PUC for an order requiring Louisiana Power and
 9                   Light Company (LP&L) to revise and increase its avoided cost
10                   estimates in determining the prices in an agreement between
11                   Calciner and LP&L. Among other matters, Calciner claimed that it
12                   should be entitled to a capacity payment as part of avoided costs
13                   and that purchased power should not be included in the dispatch
14                   model calculations. The Final Recommendation of the
15                   Administrative Law Judge in that proceeding[30] stated that
16                   purchase power needed to be a part of the economic dispatch
17                   model because at times it is the avoided supply. The ALJ also
18                   recommended that, since the Calciner contract with LP&L did not
19                   contain a legally enforceable obligation enabling the utility to rely on
20                   the power being provided by the cogenerator and to plan
21                   accordingly, that no capacity was in fact being avoided and that it
22                   would be inappropriate to include a capacity payment as a part of
23                   the avoided cost.[31] The parties in this proceeding ultimately
24                   reached a stipulation and settlement agreement regarding the
25                   proceeding.
26                       In July 1997, the PUC adopted a modified version of the
27                   settlement agreement, which agreement set a rate of 2.085 cents
28                   per kWh as the avoided cost payment due Calciner for the period


     [30]   Docket No. U-2134, Final Recommendation of the Administrative Law Judge
            dated December 5, 1996.
     [31]   The ALJ made this finding despite the fact that Calciner brought evidence to
            show that that it is on line most of the time. The ALJ noted that Calciner has
            not contracted to provide capacity. The ALJ suggested that Calciner might
            want to negotiate with LP&L to see if a capacity provision could be agreed
            upon which might allow LP&L to use its capacity in its planning activity and
            therefore entitle Calciner to a capacity payment.

                                              4-26
 1                  March 1995 through December 1997.[32] The PUC also opened a
 2                  generic rulemaking docket to establish a methodology for
 3                  determining the appropriate level of avoided costs for jurisdictional
 4                  electric utilities.[33]
 5                      In November 1997, the Louisiana PUC published a Notice of
 6                  Proposed Rulemaking (“NOPR”) concerning avoided costs
 7                  estimates.[34] In the NOPR, the PUC staff proposed using bidding
 8                  as the methodology for determining which suppliers (QF or
 9                  otherwise) will receive avoided cost capacity payments. Staff further
10                  proposed that QFs that are unsuccessful bidders or did not
11                  participate in the bidding process would not be entitled to avoided
12                  capacity payments. Staff proposed that utilities would still be
13                  required to purchase electric energy from QFs that submitted losing
14                  bids or decided not to participate. Staff further researched the
15                  methods under consideration and circulated to the electric utilities
16                  and QFs a proposed set of rules regarding which additional
17                  comments were submitted to the staff. On February 18, 1998, the
18                  Louisiana PUC adopted a General Order that it characterized as the
19                  product of a collaborative process involving Commission staff and all
20                  interested industry representatives who chose to participate.[35]
21                  The General Order proposed to amend regulations governing
22                  purchases and sales between electric utilities and QFs. The
23                  amended regulations are more specific and provide for use of an
24                  Economic Dispatch Model (on an hourly basis with actual costs
25                  being used in the model) to determine the avoided costs to be paid
26                  to QFs. The regulations further provide that rates for purchase can
27                  be negotiated, and in the case such negotiation fails, either party
28                  may submit the issue to the Commission which will resolve the
29                  matter on a case by case basis. The Economic Dispatch Model


     [32]   Order No. U-21384-B, July 16, 1997.
     [33]   Order No. U-21384-C, November 19, 1997.
     [34]   Docket No. U-22739, Notice of Proposed Rulemaking, November 7, 1997.
     [35]   General Order in Docket No. U-22739 (Amends and Supersedes Order
            No. U-14964), Decided at the February 18, 1998 Open Session.

                                            4-27
 1                  does not provide for capacity payments. QFs desiring additional
 2                  capacity payments were required to negotiate with a utility.
 3              (4) Florida
 4                      Florida has a long history of encouraging large QFs to negotiate
 5                  power purchase agreements with utilities. Most of the QF
 6                  development in Florida is the result of negotiated agreements.
 7                  Further, for plants to meet environmental review in Florida, the
 8                  Florida PUC must issue a certificate of need. Over the years the
 9                  Florida PUC has modified its QF rules somewhat, but the general
10                  principle has been that standard offer contracts are only available
11                  for: (a) QFs smaller than 100 kW; (b) municipal solid waste
12                  projects; and (c) projects with desirable fuels (biomass, waste, solar
13                  or other renewable).
14                      With respect to negotiated contracts, the PUC stated, “we find
15                  that a request for proposals continues to be a useful tool for the
16                  utility and the Commission to measure the cost-effectiveness of an
17                  IOUs capacity selection.”[36]
18                      Florida Rule 25-22.082 governs the selection of generation
19                  capacity. The rule generally provides for competitive bidding.
20                  Florida Rule 25-17.08 governs utilities’ obligations with regard to
21                  qualifying facilities. Rule 25-17.08 addresses: (a) as-delivered
22                  energy from QFs; and (b) Firm Capacity and Energy contracts.
23                  Florida Power and Light schedule COG-1, discussed below, reflects
24                  the Florida Rule regarding as-delivered energy from QFs.
25                  Negotiated contracts (with negotiations being governed by the RFP
26                  process) are the primary approach for QFs to received Firm
27                  Capacity and Energy contracts.
28                      Florida Power and Light (FPL) developed Schedule COG-1 for
29                  as-delivered energy, which is available to any QF producing energy
30                  for sale to FPL that does not have another agreement. Under this
31                  schedule, capacity payments are not made to the QFs.
32                  As-delivered energy is purchased at a unit cost based on the


     [36]   Docket No. 020398-EQ, Order No. PSC-03-0133-FOF-EQ, January 27, 2003.

                                            4-28
 1                   company’s actual hourly avoided energy cost for hours when power
 2                   is delivered. These hourly avoided energy costs are the costs that
 3                   the utility avoided by taking the energy on that hour, including
 4                   incremental fuel, identifiable operation and maintenance expense
 5                   and identifiable variable utility power purchases.[37]
 6                       Under Florida Rules, utilities and QFs are encouraged to
 7                   negotiate contracts to avoid or defer the construction of all planned
 8                   utility generating units which are not subject to the requirements of
 9                   Rule 25-22.082, F.A.C.[38] If a utility is required to issue a Request
10                   for Proposal (RFP), negotiations with QFs are governed by the
11                   utility’s RFP process. Negotiated contracts are considered prudent
12                   for cost recovery purposes if the utility demonstrates that the
13                   purchase of firm capacity and energy from the QF pursuant to the
14                   rates, terms, and other conditions of the contract can reasonably be
15                   expected to contribute towards the deferral or avoidance of
16                   additional capacity construction or other capacity-related costs by
17                   the purchasing utility at a cost which does not exceed the utility’s full
18                   avoided costs.[39]
19               (5) Washington
20                       As discussed above, while Washington state does not have as
21                   much QF development as Texas, New York, Louisiana and Florida,
22                   its movement from administratively-determined avoided cost pricing
23                   to market-based pricing is instructive here. Puget Sound Energy
24                   (“Puget”) has contracts with all QFs in Washington, totaling
25                   approximately 300 MW. In addition to these projects, some



     [37]   FP&L also has a schedule COG-2 which is available to a limited number of
            QF suppliers. The total amount of generation that is allowed to contract
            under this schedule is limited to 20 MW. Schedule COG-2 is for firm capacity
            and energy sales, pursuant to the Standard Offer Contract for the Purchase of
            Firm Capacity and Energy from a Small Power Producer or Other Qualifying
            Facility. This schedule is only available to: (a) QFs using renewable or non-
            fossil fuel; (b) QFs with a design capacity of 100 kW or less; or (c) a Solid
            Waste Facility.
     [38]   This is the Florida Rule that provides for competitive solicitations for new
            generating capacity.
     [39]   Rule 25-17.0832(2), F.A.C. (2005).

                                              4-29
 1                   additional projects Puget originally identified as being QFs have
 2                   dropped their QF status and have become EWGs.
 3                       I was employed by Puget from 1974 to 1996. While employed
 4                   at Puget, I was closely involved in implementation of PURPA
 5                   requirements from 1980 through 1996 in my position as Manager,
 6                   then Director and finally Vice-President of Power Planning. Initially
 7                   Puget paid QFs using an administratively-based avoided cost
 8                   schedule filed with the Washington state Utilities and Transportation
 9                   Commission (WUTC). The WUTC soon became concerned that the
10                   administratively determined avoided costs were too high.
11                       At about this time, the WUTC urged Puget to be more open in
12                   its Resource Planning process. The WUTC worked with Puget to
13                   develop a process for developing least-cost plans, including
14                   competitive bidding. Puget developed an Integrated Resource Plan
15                   and then a RFP to acquire needed resources on a competitive
16                   basis. Puget asked QFs to bid their products into the RFP. QFs not
17                   chosen during the RFP could still sell power to Puget, but the rate
18                   for such power was the hourly price related to the hour that the
19                   facility provides power to Puget.
20                       The WUTC agreed with Puget that use of competitive bidding
21                   was a success. The Washington Administrative Code was modified
22                   to establish rules for determining rates, terms, and conditions
23                   governing the purchases by electric utilities.[40] The Washington
24                   Administrative Code states:
25                       These rules are consistent with the provisions of the Public
26                       Utility Regulatory Policies Act of 1978 (PURPA), Title II, sections
27                       201 and 210, and regulations promulgated by the Federal
28                       Energy Regulatory Commission (FERC) in 18 C.F.R. Part 292.
29                       Purchase of electric power under these rules shall satisfy an
30                       electric utility’s obligation to purchase power from qualifying
31                       facilities under section 210 of PURPA.[41]




     [40]   W.A.C. Title 480 Chapter 107, Electric Companies—Purchases of Electricity
            From Qualifying Facilities and Independent Power Producers and Purchases
            of Electrical Savings From Conservation Suppliers.
     [41]   WAC 480-107-001(2005).

                                             4-30
 1                       Since I left Puget, there has been some modification to the
 2                   calculation of pricing for “as delivered” QF power. Today QFs
 3                   seeking long term capacity based contracts still bid their power into
 4                   Puget RFPs. QFs selling power at “as delivered” rates are paid
 5                   pursuant to a tariff that offers a monthly purchase price based on
 6                   cost of producing a unit of electricity (i.e., kWh) using simple cycle
 7                   combustion turbines or an hourly-weighted average of the Dow
 8                   Jones Mid-Columbia electricity price index for non-firm energy at on-
 9                   peak, off-peak, Sunday and NERC holiday periods, whichever is
10                   lower, less 5 percent for balancing costs.[42]
11                       In a few of the 21 states that establish QF prices through
12                   competitive solicitations, if the QF is not selected in the solicitation,
13                   the utility is not required to purchase power from the QF. Instead,
14                   the utility makes its transmission available to the QF to enable that
15                   QF to sell to another interconnected buyer. In 15 states, a QF not
16                   selected in a utility solicitation sells its output to the utility pursuant
17                   to an energy-only “as-delivered” contract.[43] No capacity payment
18                   is made pursuant to such an energy-only contract since the utility
19                   has met its capacity needs through its competitive solicitation. The
20                   rate for energy-only as-delivered contracts is generally determined
21                   by a market index or hourly economic dispatch model using actual
22                   market prices as inputs.
23           d. States Using Published or Administratively Determined Avoided Cost
24               Rates
25                   Six states require utilities to publish administratively-determined QF
26               long-term and/or short-term prices.[44] Excluding California (which
27               hosts 14% of QF MWs), the MW of QF contracts in these states makes
28               up less than 2 percent of the QF projects in the United States. The
29               rates and amount of QF purchases are litigated in time-consuming


     [42]   WUTC Docket UE-010951 – August 2001.
     [43]   Connecticut, Delaware, Maine, Maryland, Massachusetts, Montana, Nevada,
            New Hampshire, New Jersey, New York, Ohio, Pennsylvania, Rhode Island,
            Virginia, Washington.
     [44]   Idaho, Illinois, Kentucky, Tennessee, Utah, California.

                                               4-31
 1           proceedings before the state public utilities commissions. These
 2           administratively determined energy-only prices for as-delivered power
 3           sales usually include a formula to update the price if key assumptions
 4           change or to ensure these energy-only avoided costs are reflective of
 5           current conditions. It appears that only California and Hawaii currently
 6           pay short-term as-delivered energy prices under QF contracts using a
 7           formula where the heat rate was locked in a number of years ago and
 8           fuel costs are indexed monthly.
 9      e.   States That Determine Avoided Costs on a Contract-By-Contract
10           Basis
11               In the remaining 20 states, long-term and short-term avoided costs
12           rates are generally determined on a case-by-case basis through
13           negotiations between the QF and the utility. We consider contract by
14           contract negotiations of prices for QF power to be “market based”
15           determination of avoided costs. In some cases, PUC decisions or utility
16           tariff language outline an avoided-cost framework for the negotiations.
17           Disputes are taken to the PUC for resolution.

18   3. Conclusions and Observations
19           Most states are using market mechanisms such as competitive bidding
20      or individual negotiated contracts to determine avoided costs. These states,
21      hosting 84 percent of the QF power currently existing, have concluded that
22      the best way for utilities to procure QF power is through use of market
23      mechanisms. California stands out as the only state with sizable QF activity
24      that sets its QF contract rates administratively. For regulators and utilities, a
25      competitive process reduces the burden of estimating avoided cost because
26      the market establishes the incremental cost to the electric utility of the
27      needed energy and capacity. It also minimizes disputes about the accuracy
28      of the avoided cost rate.
29           California is dealing with many of the same PURPA implementation
30      issues other states have addressed. Ensuring that a price paid to a QF
31      does not exceed the utility’s “avoided cost” is best achieved when all the
32      supplies compete in a solicitation for the needed power. A large number of
33      states have turned to the market to determine avoided costs, both for
34      long-term purchases and for as delivered power. States that are currently

                                          4-32
 1             entering into new “as-delivered” power contracts do not require separate
 2             capacity payments for such as-delivered power.
 3                 PG&E’s proposal for the reform of SRAC energy prices and for new and
 4             expiring QF contracts is consistent with the nationwide trend toward
 5             market-determined QF rates.

 6   C. Load and Resources (La Flash)
 7          1. PG&E’s Long-Term Plan
 8                 PG&E’s Long-Term Plan was approved by the Commission in
 9             Decision 04-12-048: The Commission stated:
10                 We find that PG&E’s LTPP plan is reasonable and we approve PG&E’s
11                 strategy of adding 1,200 MW of capacity and new peaking generation in
12                 2008 and an additional 1,000 MW of new peaking and dispatchable
13                 generation in 2010 through RFOs because it is compatible with PG&E’s
14                 medium resource needs, does not crowd out policy-preferred resources,
15                 and is a reasonable level of commitment given load uncertainty.[45]

16                 PG&E’s approved plan assumes that 90 percent of expiring QFs would
17             continue to sell to PG&E, at their current load factor, after their contracts
18             expire.
19                 QFs with expiring contracts from 2006 through 2014 are summarized in
20             Table 4-4. From Table 4-4, 119 MWs (average) of deliveries from QFs
21             could expire during 2006 and 2007. This amount of capacity can easily be
22             replaced, if necessary. Since PG&E resumed power procurement in 2003, it
23             has conducted 12 formal solicitations:
24             •   Two Long-Term – 5 years or greater (one active);

25             •   Two Intermediate Term – 2-5 years;

26             •   Two Long-Term Renewables – 10-20 years RPS; and

27             •   Six Short-Term – less than 3 years.

28                 Consequently, in the near term, PG&E should have adequate reserves
29             even with expiring QF contracts.
30                 Furthermore, PG&E has issued a request for offers in compliance with
31             the LTPP decision (D.04-12-048). The response to the solicitation provides
32             a robust indication that more than enough market-priced capacity is


     [45]     D.04-12-048, Finding of Fact No. 19, mimeo at p. 181.

                                                 4-33
 1           available to offset expiring contracts, if they choose to close their facilities,
 2           as well as meet new load demands. While the results of the solicitation are
 3           confidential, one can draw the same conclusion from public information. For
 4           example, a February 2005 presentation[46] shows northern California has
 5           adequate reserves without adding new resources through 2009 under the 1-
 6           in-2 forecast peak load, and through 2007 under a more conservative 1-in-
 7           10 peak load forecast.
 8               The current Long-Term Solicitation is typical of the competitive process
 9           PG&E plans to use to procure most of its long-term power. It has the
10           following basic characteristics:
11           •   All-source, open to all types of generation: EWGs, QFs, Renewables,
12               Power Marketers;

13           •   Multi-attribute evaluation, including:

14               1. Market value;
15               2. Portfolio fit;
16               3. Credit;
17               4. Location and transmission impact;
18               5. Environmental characteristics; and
19               6. Project viability and participant qualifications.
20           •   Model contract terms; and

21           •   Use of an independent evaluator.

22               In the 2008 to 2011 time period, an additional 632 MWs (average) of
23           deliveries from QFs could expire. Again, publicly available information
24           indicates that abundant new market-priced capacity is under development to
25           offset expiring contracts. The California Energy Commission’s (CEC) siting
26           status report[47] shows 4,352 MW of generation capacity approved and
27           under construction. A large share of the capacity is in northern California.
28           Another 8,173 MW is approved and “available” for construction. Also, the




     [46]   Staffs of the: California Energy Commission, California Public Utilities
            Commission, and California Independent System Operator California’s
            Electricity Situation: Summer 2005, February 22, 2005.
     [47]   See “http://www.energy.ca.gov/sitingcases/all_projects.html.”

                                                4-34
 1             CAISO has identified 87 projects with interconnection applications that
 2             represent over 21,000 MW of new capacity.[48]

 3          2. Re-Contracting Options
 4                 A cogenerator needing to upgrade its facility can bid into a PG&E RFO
 5             to secure a contract on which it can rely to finance its upgrades.
 6             Cogenerators have a substantial head start in these RFOs. They would be
 7             proposing “brown field” development of an existing facility, with permits and
 8             emission allowances in place and a power plant that probably has already
 9             been substantially depreciated and has had its debt retired. Compared to
10             new projects that must recover their initial capital cost, existing cogenerators
11             should be able to offer very competitive pricing.
12                 In PG&E’s long-term RFO, QF resources have been given an exception
13             to the minimum 25 MW requirement, and must be only 1 MW or greater in
14             size. QFs also are the only bidders who may bid baseload or incremental
15             generation profiles.
16                 PG&E will consider offers in its solicitations that meet the specifications
17             noted below:
18             •   Power Purchase

19                 (1) New generating facilities, defined as facilities that have a
20                      Commercial Operations Date no earlier than January 1, 2007, for
21                      the delivery of the products (capacity, energy and ancillary services)
22                      commencing no earlier than January 1, 2007, and not later than
23                      May 31, 2010. PG&E’s preference is for deliveries beginning
24                      between January 1 and June 1 in 2008, 2009 or 2010.
25                 (2) An existing QF in PG&E’s service territory as of November 2, 2004,
26                      that meets the FERC definition of a QF and has not waived these
27                      rights as regards to PG&E.
28                 (3) Minimum offer term of five years.
29                 (4) The Participant must provide for firm physical delivery of its
30                      generation to a busbar at a specified delivery point (designated by




     [48]     See “http://www2.caiso.com/thegrid/planning/geninterconnect/isointconqueue.html.”

                                                 4-35
 1                   Seller) within the area designated as NP15, as presently defined by
 2                   CAISO.[49]
 3               As part of the solicitation, PG&E has also offered QFs the opportunity to
 4           terminate their existing or expiring contracts without payment of liquidated
 5           damages in return for a long-term, market-based contract. Any long-term
 6           contracts for future deliveries must be competitive with other supply options
 7           to avoid placing new stranded costs on utility customers.
 8               A QF with a current contract with PG&E with an expiration date after
 9           2010 can still submit a bid into the RFO. QF participants that have ongoing
10           contract commitments must provide an offer with price, terms and conditions
11           assuming the ongoing QF commitment is terminated. The QF bidder must
12           set forth its plan to terminate any ongoing QF commitments to enable PG&E
13           to evaluate the viability of the QF bid. It is anticipated that any arrangement
14           for the termination of an ongoing QF commitment will be approved by the
15           CPUC if a QF offer is a winning offer under the LT RFO and a contract is
16           executed and submitted to the CPUC for approval.
17               Assuming all other eligibility requirements are met, the bid would be
18           considered compliant. The bid should incorporate a proposed termination of
19           the remaining portion of the existing QF contract at the initial delivery date of
20           the new PPA. Capacity from a new QF, or new incremental capacity from
21           an existing QF, will count toward the target for the long-term RFO. Existing
22           capacity from an existing QF will not count toward the target for the
23           long-term RFO.




     [49]   QFs interconnected at the Midway Substation are considered eligible to bid
            as if delivered into NP15 and other QFs in ZP26 that can provide firm physical
            deliveries to NP15 are eligible to bid into the PPA RFO.

                                              4-36
PACIFIC GAS AND ELECTRIC COMPANY

           APPENDIX C

  STATEMENT OF QUALIFICATIONS
1                 PACIFIC GAS AND ELECTRIC COMPANY
2          STATEMENT OF QUALIFICATIONS OF CAROLYN A. BERRY

3    Q 1     Please state your name, occupation, and business address.
4    A 1     My name is Carolyn A. Berry. I am an economic consultant located at
5            7041 Western Ave. NW Washington, DC.
6    Q 2     Briefly describe your responsibilities as an economic consultant.
7    A 2     I am a consultant who specializes in market design, policy formation, and
8            regulatory issues in the electric power industry. My work has been focused
9            in the areas of electricity market design, ancillary services market design,
10           regional transmission organization development, investment strategy,
11           electricity trade, and federal regulation for a variety of clients both in the U.S.
12           and abroad. I have done extensive work in the California energy markets
13           and, for the last several years, in the California refund proceedings.
14   Q 3     Please summarize your educational and professional background.
15   A 3     I received a Bachelor of Science degree in Economics and a Bachelor of
16           Arts degree in Spanish from the University of Minnesota. I received a Ph.D.
17           in Economics from Northwestern University in Illinois.
18                From 1989-1992, I worked as a lecturer in the Economics Department
19           at Northwestern University. From 1992-1993, I was an assistant professor
20           in the Economics Department at the Universitat Pompeu Fabra in
21           Barcelona, Spain. From 1994-2000, I worked as an economist at the
22           Federal Energy Regulatory Commission (FERC) in Washington, D.C. in the
23           Office of Administrative Litigation and Office of Economic Policy. From
24           2000-2001, I worked at National Economic Research Associates as a senior
25           consultant. In 2002, I joined Charles River Associates as a principal. Later
26           that same year I began working as an independent consultant.
27                I have provided consulting services and prepared expert testimony on
28           a range of electric industry cases and issues. I have provided support and
29           analysis covering a wide variety of electric and natural gas issues to Pacific
30           Gas and Electric Company, Southern California Edison Company, the
31           People of the State of California ex rel, Bill Lockyer, Attorney General, the
32           California Public Utilities Commission, and the California Electricity
33           Oversight Board in the ongoing California Refund Proceeding.


                                              CAB-1
1         Examples of expert testimony in proceedings at both the federal and
2    state level include:
3    •    Declaration on Behalf of the California Entities in support of “California
4         Entities’ Petition to Intervene and Protest Application of Powerex
5         Corporation for Renewal of Export License,” Department of Energy,
6         Office of Coal and Power, Import/Export Office of Fossil Energy,
7         Docket No. EA-171-B, March 7, 2005.
8    •    Reply Declaration on Behalf of the California Parties in support of
9         “California Parties’ Reply Comments on the Substance, Format and
10        Support for Cost-Based Filings,” in San Diego Gas & Electric Company
11        v. Sellers of Energy and Ancillary Services, Docket Nos. EL00-95 and
12        EL00-98, January 19, 2005.
13   •    Declaration on Behalf of the California Parties in support of “California
14        Parties’ Comments on the Substance, Format and Support for Cost-
15        Based Filings,” in San Diego Gas & Electric Company v. Sellers of
16        Energy and Ancillary Services, Docket Nos. EL00-95 and EL00-98,
17        January 10, 2005.
18   •    Declaration in support of “California Parties’ Request for Rehearing of
19        May 12 Order on Requests for Rehearing and Clarification,” in San
20        Diego Gas & Electric Company v. Sellers of Energy and Ancillary
21        Services, Docket Nos. EL00-95-087, et al., (regarding the decision to
22        mitigate the $2.9 billion of imbalance energy sales by CERS),
23        June 4, 2004.
24   •    Declaration in support of “California Parties’ Request for Rehearing of
25        Order Approving Contested Settlement Agreement Between FERC
26        Trial Staff and Powerex Corporation,” in Powerex Corp., Docket Nos.
27        EL03-166-000, et al., April 26, 2004.
28   •    Declaration in support of “Opening Comments of Pacific Gas and
29        Electric Company, the Office of Ratepayer Advocates, and the Utility
30        Reform Network Regarding Qualifying Facility SRAC Payments From
31        December 2000 Through March 2001,” R.99-11-022,
32        February 17, 2004.
33   •    Declaration in support of “California Parties’ Request For Rehearing of
34        Order Approving Stipulation and Consent Agreement With Duke,” in


                                    CAB-2
1         Duke Energy North America LLC and Duke Energy Trading and
2         Marketing LLC, Docket Nos. IN03-10-000, PA02-2-000, et al.,
3         January 20, 2004.
4    •    Declaration in support of “California Parties’ Comments in Opposition
5         to Proposed Agreement and Stipulation by Powerex Corp. and FERC
6         Trial Staff,” in Powerex Corp., Docket Nos. EL03-166-000,
7         EL03-199-000, et al., November 20, 2003.
8    •    Declaration in support of “Comments of Pacific Gas and Electric
9         Company and Southern California Edison Company in Opposition to
10        the Williams Settlement,” in Williams Energy Services Corporation,
11        Docket No. EL03-179-000 et al., September 30, 2003.
12   •    Declaration on Behalf of the California Parties in support of “California
13        Parties’ Motion to Reject Gas Cost Allowance Filings, Clarify Scope of
14        Permissible Costs, and Establish Procedures,” in San Diego
15        Gas & Electric Company v. Sellers of Energy and Ancillary Services,
16        Docket Nos. EL00-95-045 and EL00-98-042, May 21, 2003.
17        I have authored numerous publications and presentations in the area
18   of electricity market deregulation and oversight. A selection of these
19   includes the following:
20   •    “Market Power Analysis of the Electricity Generation Sector,” by
21        William H. Hieronymous, J. Stephen Henderson, and Carolyn A. Berry,
22        Energy Law Journal, Vol.23, No.1 (2002).
23   •    “Understanding how Market Power Can Arise in Network Competition:
24        A Game Theoretical Approach,” by Carolyn A. Berry, Benjamin F.
25        Hobbs, William A. Meroney, Richard P. O’Neill, and William R. Stewart,
26        Jr., Utilities Policy, Vol.8, No.3 (September 1999).
27   •    “Why are nodal prices sometimes higher than $1000 in PJM if supply
28        bids are capped at $1000?” economic note, FERC, August 1999.
29   •    “Congestion, Transmission Loading Relief, and Reliability,” written
30        comments for Infocast Conference on Congestion Management,
31        Washington, DC, March 25, 1999.
32   •    “California Energy Crisis,” Kogod Interative 2002 3rd Annual MBA
33        Conference on Business Trends, American University Kogod School of
34        Business, Washington, DC., February 23, 2002.


                                    CAB-3
1          •    “California Electric Industry Restructuring: What Went Wrong? Where
2               Do We Go From Here?” Forum for Women State Legislators, Power
3               Politics: Energy Policy in the States, Dana Point, CA,
4               November 17, 2001.
5          •    “Distribution Services Under Retail Access,” World Bank Presentation,
6               Washington, DC, June 21, 2001.
7          •    “California Power Crisis: Can It Happen To Us?” Presentation to
8               Iberdrola, New York, NY, February 6, 2001.
9          •    “California Power Crisis: Implications for Power Sector Reform in
10              Emerging Economies?” Seminar to Energy Markets and Reform
11              Thematic Group, World Bank, made jointly with William Meroney,
12              FERC, January 11, 2001.
13         •    “California Electricity Markets and the Summer 2000,” Presentation to
14              the Brazilian Guaraniana Group, Washington, DC,
15              November 29, 2000.
16         •    “California Electricity Markets, with Comments on Western Power
17              Trading,” Presentation to Iberdrola, New York, NY, October 17, 2000.
18   Q 4   What is the purpose of your testimony?
19   A 4   I am sponsoring Chapter 3, Section D, “Proposed SRAC Energy Prices,”
20         and Appendix B, Section A, “SRAC Energy Overpayment.”
21   Q 5   Does this conclude your statement of qualifications?
22   A 5   Yes, it does.




                                         CAB-4
 1               PACIFIC GAS AND ELECTRIC COMPANY
 2         STATEMENT OF QUALIFICATIONS OF KEVIN F. COFFEE

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Kevin F. Coffee, and my business address is Pacific Gas and
 5         Electric Company, 245 Market Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I am the energy trading manager in the Power Trading Department.
 8   Q 3   Please summarize your educational and professional background.
 9   A 3   I earned a Bachelor and Master of Science degree in Electrical Engineering
10         from New Mexico State University 1984. I joined PG&E in 1984 as a power
11         systems engineer. From 1993 to 1995, I was a lead wholesale account
12         representative and from there, moved into PG&E’s Marketing Department
13         where I was an energy marketing consultant until 1997. In 1997, I joined
14         PG&E energy services as a director of operations and in 2000, moved to
15         E-lec Trade as a director of operations. In 2002, I returned to PG&E to
16         assume my current responsibilities as the energy trading manager in the
17         power trading group.
18   Q 4   What is the purpose of your testimony?
19   A 4   I am sponsoring Chapter 3, Section B, “NP-15 Prices Are PG&E’s Short-Run
20         Avoided Energy Cost Because PG&E Relies on NP-15 Prices for Dispatch
21         Decisions” in the QF Avoided Cost proceeding.
22   Q 5   Does this conclude your statement of qualifications?
23   A 5   Yes, it does.




                                          KFC-1
 1              PACIFIC GAS AND ELECTRIC COMPANY
 2         STATEMENT OF QUALIFICATIONS OF FRANK DE ROSA

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Frank De Rosa, and my business address is Pacific Gas and
 5         Electric Company, 245 Market Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I am the director of power contracts in PG&E’s Power Contracts & Electric
 8         Resource Development organization. I am responsible for the management
 9         of PG&E's existing wholesale contracts, including QFs, DWR, Irrigation
10         District, Renewables, RMR, and other bilateral contracts. I am also
11         responsible for PG&E's structured contract procurement, including the
12         renewable RPS solicitation and solicitations for conventional power.
13   Q 3   Please summarize your educational and professional background.
14   A 3   I received a Bachelor of Arts in Biology and English from Boston University
15         in 1977. In 1982, I received a Master of Arts in Public Policy from the
16         Kennedy School of Government at Harvard University. From 1978-1980,
17         I worked as a policy analyst in the Massachusetts Energy Office. From
18         1982-1984 I worked as a budget analyst in the Executive Office of the
19         President, U. S. Office of Management and Budget. I joined PG&E in 1984
20         and through 1988, held various positions in finance and corporate planning.
21         From 1988-2003, I worked for PG&E National Energy Group, the last
22         10 years as vice president of the western region. In that role I managed all
23         aspects of the business in the 11 states in the western region including
24         market assessment, project development, power and gas marketing and
25         sales, business development and strategic planning. I returned to the utility
26         in 2003, when I assumed my current position.
27   Q 4   What is the purpose of your testimony?
28   A 4   I am sponsoring Executive Summary, Chapter 1, and Chapter 4, Section A,
29         “Introduction.”
30   Q 5   Does this conclude your statement of qualifications?
31   A 5   Yes, it does.




                                           FD-1
 1             PACIFIC GAS AND ELECTRIC COMPANY
 2     STATEMENT OF QUALIFICATIONS OF PETER S. FOX-PENNER

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Peter S. Fox-Penner and my business address is The Brattle
 5         Group, Washington, DC.
 6   Q 2   Briefly describe your responsibilities at The Brattle Group.
 7   A 2   I am a principal and chairman of the board. Brattle is the successor firm
 8         resulting from the merger of The Brattle Group, Inc. with Incentives
 9         Research, Inc. I direct the firm’s external strategy formulation and
10         execution.
11   Q 3   Please summarize your educational and professional background.
12   A 3   I received a Bachelor of Science degree in Electrical Engineering (1976),
13         and Master of Science degree in Mechanical Engineering (Energy Policy,
14         1978) from the University of Illinois. In 1989, I received a Ph.D. in
15         Economics from the Graduate School of Business, University of Chicago.
16         From 1977-1980, I was a research assistant and research engineer, Office
17         of Vice Chancellor for Energy Research, University of Illinois. From
18         1980-1983, I worked as a research engineer and chief research engineer in
19         the Illinois Governor’s Office of Consumer Service. From 1987-1993,
20         I worked at Charles River Associates first as a senior associate and then
21         vice president. From 1991-1993, I was also a professorial lecturer at the
22         Center for Energy and Environmental Studies, Boston University. From
23         1993-1996, I served as principal deputy assistant secretary for Energy
24         Efficiency and Renewable Energy, United States Department of Energy;
25         senior advisor for technology policy, Office of Science and Technology
26         Policy, Executive Office of the President; and assistant to the deputy
27         secretary of energy. From 1996 onwards, I have been a principal and
28         director at The Brattle Group, Washington, DC. In 2001, I also assumed the
29         role of chairman at The Brattle Group.
30              I have authored numerous publications and books in the area of
31         electricity market deregulation and oversight. A selection of refereed
32         publications includes the following:




                                           PSF-1
 1   •   With James Bohn, Romkaew Broehm, and Gary Taylor, “The
 2       Regulation of Competition in Wholesale Electric Power Markets.”
 3       Energy Law Journal 23, No. 2 (2002): 281-348.
 4   •   With Gregory N. Basheda, Darrell B. Chodorow, Jason A. Hicks, Eric
 5       Hirst, James K. Mitchell, Dean M. Murphy and Joseph B. Wharton,
 6       “The FERC, Stranded Cost Recovery, and Municipalization.” Energy
 7       Law Journal 19 (1998): 351-386.
 8   •   “Efficiency and the Public Interest: QF Transmission and the Energy
 9       Policy Act of 1992.” Energy Law Journal 14 (1993): 51-73.
10   •   With Karen Palmer, David Simpson, and Michael Toman, “Electricity
11       Fuel Contracting: Relationships with Coal and Gas Suppliers.” Energy
12       Policy, October 1993: 1045-1054.
13   •   With Franklin M. Fisher, Joen Greenwood, William G. Moss, and
14       Almarin Phillips, “Due Diligence and the Demand for Electricity: A
15       Cautionary Tale.” Journal of Industrial Organization, 1992.
16   •   “Cogeneration After PURPA: Energy Conservation and Industry
17       Structure.” Journal of Law and Economics 33 (October 1990):
18       517-552.
19   •   “Regulating Independent Power Producers: Lessons of the PURPA
20       Approach.” Resources and Energy 12 (1990): 117-141.
21       A selection of my monographs, books, and book chapters:
22   •   “Electric Utility Restructuring: A Guide to the Competitive Era.” Vienna,
23       VA: Public Utility Reports, 1997.
24   •   With Karen Palmer, David Simpson, and Michael Toman, “Power Plant
25       Fuel Supply Contracts: The Changing Nature of the Long-Term Supply
26       Relationship.” Arlington, VA: Public Utility Reports, 1992.
27   •   “Electric Power Transmission and Wheeling: A Technical Primer.”
28       Washington, DC: The Edison Electric Institute, 1990.
29   •   With Karen Palmer, David Simpson, and Michael Toman, “Power Plant
30       Fuel Supply Contracts the Changing Nature of the Long-Term Supply
31       Relationship.” Arlington, VA: Public Utility Reports, 1992.
32   •   “What Role Should the Federal Government Play in Energy
33       Efficiency?” in Policy Evolution: Energy Conservation to Energy




                                   PSF-2
 1       Efficiency. Douglas A. Decker and Alan Berolzheimer, eds. Liburn,
 2       GA: The Fairmount Press, 1997.
 3       A selection of my other publications includes the following:
 4   •   “U.S. Needs a Plan to Keep the Lights On.” The Plain Dealer,
 5       August 26, 2004.
 6   •   “A Year Later, Lessons from the Blackout.” The New York Times,
 7       August 15, 2004.
 8   •   “Rethinking the Grid–Avoiding More Blackouts and Modernizing the
 9       Power Grid is Harder than You Think.” April 2004.
10   •   With Romkaew Broehm, “Deregulated Electricity Pricing in the U.S.:
11       Dramatic New Rules From the FERC.” The Brattle Group,
12       April 25, 2004.
13   •   “Will Federal Legislation Fix the Grid?” Progressive Policy Institute,
14       October 7, 2003.
15   •   With Greg Basheda, “State Involvement in the Regional Transmission
16       Planning Process.” The Edison Electric Institute, October 2003.
17   •   “Easing Gridlock on the Grid: Electric Planning and Siting Compacts.”
18       The Electricity Journal, November 2001.
19   •   “Clean Growth: A Balanced Energy Policy for the 21st Century.”
20       Progressive Policy Institute’s Policy Report, October 2001.
21   •   With Greg Basheda, “A Short Honeymoon for Utility Deregulation.”
22       Issues in Science and Technology, Spring 2001.
23   •   “What Not to Learn From the California Crisis.” (Op-ed) The
24       Providence Journal, March 3, 2001.
25   •   “Epitaph for Electric Deregulation.” Prepared for the National Council
26       on Competition and the Electric Industry, December 2000 meeting,
27       October 2000.
28   •   With Frank Graves, “Monopoly Power After Reform? A Time for Soul-
29       Searching.” Public Utilities Fortnightly, May 2000.
30   •   “Federal Restructuring Legislation: Any Chance in This Congressional
31       Session?” Energy Efficiency Journal, March 2000.
32   •   “Electric Power Deregulation: Blessings and Blemishes, A Non-
33       Technical Review of the Issues Associated With Competition in




                                   PSF-3
 1              Today’s Electric Power Industry.” Prepared for the National Council on
 2              Competition and the Electric Industry, March 14, 2000.
 3         •    With Johannes P. Pfeifenberger, “Transmission Access, Episode II:
 4              FERC’s Journey.” Public Utilities Fortnightly, August 1999.
 5         •    With J.P. Pfeifenberger, P.Q Hanser, and G.N. Basheda, “In What
 6              Shape is Your ISO?” The Electricity Journal, July 1998.
 7         •    “Transco vs. ISO: A Sideshow?” Public Utilities Fortnightly,
 8              June 1, 1998.
 9         •    With Matt O’Loughlin, “Fostering Market Center Development and
10              Integration of the Natural Gas Grid Through Improved Pipeline
11              Ratemaking.” Prepared for NorAm Gas Transmission Company,
12              May 1998.
13         •    “An Open Letter to the President.” The Electricity Journal,
14              March 1997.
15         •    With Philip Q Hanser and Joseph B. Wharton, “Real-Time Pricing:
16              Restructuring’s Big Bang?” Public Utilities Fortnightly, March 1997.
17         •    “Critical Trends in State Utility Regulation.” Natural Resources and
18              Environment 8 (Winter 1994): 17-20.
19   Q 4   What is the purpose of your testimony?
20   A 4   I am sponsoring parts of Chapter 3, Section C, “Assessment of PG&E’s
21         SRAC Proposal,” and Appendix A, “Analysis of Competitive Conditions in
22         California ISO Spot Markets.”
23   Q 5   Does this conclude your statement of qualifications?
24   A 5   Yes, it does.




                                           PSF-4
 1            PACIFIC GAS AND ELECTRIC COMPANY
 2     STATEMENT OF QUALIFICATIONS OF HAROLD O. LA FLASH

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Harold O. La Flash, and my business address is Pacific Gas
 5         and Electric Company, 245 Market Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I am the director of integrated resource planning and policy in PG&E’s gas
 8         and electric supply organization.
 9   Q 3   Please summarize your educational and professional background.
10   A 3   I earned a Bachelor of Science degree in Mechanical Engineering from the
11         University of Wisconsin – Madison, and a Masters in Business
12         Administration degree from Saint Mary’s College, Moraga, California. I
13         joined PG&E in January 1980 and have held various positions involving
14         energy efficiency, nonutility generation, tariffs, and gas transportation. In
15         1997, I moved to PG&E Corporation where I held positions in corporate
16         development and business planning. I returned to the utility in
17         January 2004, when I assumed my current position.
18   Q 4   What is the purpose of your testimony?
19   A 4   I am sponsoring Chapter 4, Section C, “Load and Resources,” of PG&E’s
20         Prepared Testimony on Qualifying Facilities (QF) Policy and Pricing Issues.
21   Q 5   Does this conclude your statement of qualifications?
22   A 5   Yes, it does.




                                           HOL-1
 1            PACIFIC GAS AND ELECTRIC COMPANY
 2    STATEMENT OF QUALIFICATIONS OF J. RICHARD LAUCKHART

 3   Q 1   Please state your name and business address.
 4   A 1   My name is J. Richard Lauckhart. My business address is 2379 Gateway
 5         Oaks Drive, Suite 100, Sacramento, California.
 6   Q 2   Briefly describe your responsibilities.
 7   A 2   I am the Vice President of Global Energy Advisors (a unit of Global Energy
 8         Decisions aka Henwood) and oversee WECC Power Market Analysis,
 9         Global Energy and head the firm’s MarketSym/LMP consulting team in
10         assignments across the United States and Canada. Global Energy provides
11         power market advisory services to electric utilities, independent power
12         producers, marketers, investment banks, rating agencies and large energy
13         consumers. Global Energy technology and electric market modeling and
14         simulation software are currently used by more than 130 market leading
15         energy companies worldwide to plan, schedule and optimize their electric
16         generation.
17   Q 3   Please summarize your educational and professional background.
18   A 3   I received a Bachelor of Science degree in Electrical Engineering from
19         Washington State University in 1971 and a Masters degree in Business
20         Administration from the University of Washington in 1975. At Global Energy,
21         I am the head of their WECC Regional Power Advisory Service leading a
22         team of experienced power professionals in consulting assignments
23         throughout the western power markets of the United States. I am
24         responsible for providing western power market analyses, price forecasting
25         services and management of strategic consulting engagements for clients in
26         the WECC markets. I joined Global Energy (then known as Henwood) in
27         August 2000. I have actively been involved in power supply planning,
28         electricity price forecasting and asset valuation for more than 30 years.
29         Before joining Global Energy I was President of Lauckhart Consulting, Inc.,
30         from 1996 to 2000 providing price forecasting and electric interconnection
31         and transmission analysis for power projects. From 1974 to 1996, I held
32         various positions at Puget Sound Power & Light Company in power supply




                                            JRL-1
 1         planning culminating my service as Vice President of Power Planning for the
 2         last four years of my tenure.
 3   Q 4   Please indicate your prior testimony experience.
 4   A 4   I have provided testimony in the following matters:
 5         •   Expert Testimony for BC Hydro regarding the expected operation of the
 6             proposed Duke Point Power Project on Vancouver Island,
 7             January 2005;
 8         •   Expert Testimony for PG&E regarding the cost alternative generation to
 9             the proposed replacement of steam generators for Diablo Canyon,
10             summer 2004;
11         •   Expert Testimony in an arbitration over a dispute about failure to deliver
12             power under a Power Purchase Agreement, fall 2004;
13         •   Integrated Resource Plan Development: testimony on behalf of each of
14             SDG&E, SCE and PG&E in spring 2003;
15         •   Pre-filed testimony on Marginal Cost in SCE General Rate Case filed in
16             October 2002;
17         •   Miguel-Mission Transmission Market Analysis-San Diego Gas & Electric
18             Company. San Diego Gas & Electric Company retained Global Energy
19             to oversee an analysis of the economic benefits associated with building
20             the Mission-Miguel transmission line and the Imperial Valley
21             transformer. Global Energy performed an analysis of the economic
22             benefits of the Mission-Miguel line, prepared a report, sponsored
23             testimony at the CPUC, and testified at the CPUC regarding the report;
24         •   Valley-Rainbow Transmission Market Analysis-San Diego Gas & Electric
25             Company. San Diego Gas & Electric Company also engaged Global
26             Energy to analyze the economic benefits associated with building the
27             Valley-Rainbow transmission line and to respond to the CPUC scoping
28             memo that “SDG&E should describe its assessment of how a 500 kV
29             interconnect, like Valley-Rainbow, will impact electricity markets locally,
30             regionally, and statewide.” Global Energy analyzed the economic
31             benefits of the Valley-Rainbow line, prepared a report, sponsored
32             testimony at the CPUC, and testified at the CPUC regarding the report;
33         •   Damages Assessment Litigation Support. Global Energy was engaged
34             by Stoel Rives to provide damages analysis, expert testimony and


                                           JRL-2
 1       litigation support in for its client in a power contract damages lawsuit.
 2       Global Energy quantified the range of potential damages, assessed
 3       power market conditions at the time, and provided expert testimony to
 4       enable Stoel Rives’ client to prevail in a jury trial;
 5   •   Expert Testimony, Concerning the Economic Benefits Associated with
 6       Transmission Line Expansion. Testimony prepared on behalf of
 7       San Diego Gas & Electric Company, September 2001;
 8   •   Expert Testimony, Concerning market price forecast in support of Pacific
 9       Gas and Electric Company hydro divesture case, December 2000;
10   •   Expert Testimony, Prepared on behalf of AES Pacific regarding value of
11       sale for Mohave Coal project to AES Pacific for Southern California
12       Edison, December 2000; and
13   •   Expert Testimony, Prepared on behalf of a coalition of 12 entities
14       regarding the impact of Direct Access of utility costs in California.
15       June 2002.
16       Mr. Lauckhart was Puget’s primary witness on power supply matters in
17   the following cases:
18
19       Cause No.                    Year               Description of proceeding
20       UE901183                    1990                Proceeding to initiate a
21                                                       power cost recover
22                                                       mechanism
23       UE910626                    1991                Initial power cost pass
24                                                       through proceeding
25                                                       (PRAM1)
26       UE920630                    1992                Second power cost pass
27                                                       through proceeding
28                                                       (PRAM2)
29       UE920433                    1992                Review of prudency of long-
30                                                       term resource acquisitions
31       UE921262                    1992                General Rate Case
32       UE930622                    1993                Third power cost pass
33                                                       through Proceeding
34                                                       (PRAM3)
35       UE940728                    1994                Fourth power cost pass
36                                                       through proceeding
37                                                       (PRAM4)



                                       JRL-3
 1                 UE950618                 1995              Fifth power cost pass
 2                                                            through proceeding
 3                                                            (PRAM5)

 4             Mr. Lauckhart was also Puget’s chief witness at FERC in hearings involving
 5         Puget’s Open Access Transmission Tariff and testified for Puget in BPA rate
 6         case and court proceedings.
 7   Q 5       What is the purpose of your testimony?
 8   A 5       I am sponsoring Chapter 4, Section B, “Implementation of PURPA in Other
 9             States.”
10   Q 6       Does this conclude your statement of qualifications?
11   A 6       Yes, it does.




                                              JRL-4
 1              PACIFIC GAS AND ELECTRIC COMPANY
 2         STATEMENT OF QUALIFICATIONS OF JOHN S. PAPPAS

 3   Q 1   Please state your name and business address.
 4   A 1   My name is John S. Pappas, and my business address is Pacific Gas and
 5         Electric Company, 245 Market Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I am a manager in PG&E’s Power Contracts and Electric Resource
 8         Development Department, which procures forward power and resource
 9         development contracts on behalf of PG&E’s retail load. I am responsible for
10         renewable energy procurement policy and contract administration with
11         respect to qualifying facilities.
12   Q 3   Please summarize your educational and professional background.
13   A 3   I earned a Bachelor of Science degree in Mechanical Engineering from
14         Brown University, Providence, Rhode Island, in 1977. I earned a Masters
15         degree in Business Administration from Golden Gate University in 1984. I
16         joined PG&E in 1977, gaining increasing responsibility on matters relating to
17         qualifying facilities.
18   Q 4   What is the purpose of your testimony?
19   A 4   I am sponsoring Chapter 3, Section A, “Outline of PG&E Pricing Proposal for
20         Existing QF Contracts.”
21   Q 5   Does this conclude your statement of qualifications?
22   A 5   Yes, it does.




                                               JSP-1
 1            PACIFIC GAS AND ELECTRIC COMPANY
 2    STATEMENT OF QUALIFICATIONS OF DANIEL D. RICHARD, JR.

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Daniel D. Richard, Jr. and my business address is Pacific Gas
 5         and Electric Company, 77 Beale Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I am Senior Vice President of Public Policy and Governmental Affairs for
 8         Pacific Gas and Electric Company and PG&E Corporation. I am responsible
 9         for all governmental relations, regulatory relations and communications, and
10         for coordinating the overall direction for PG&E’s public policy development,
11         providing the integration of initiatives in the areas of procurement, energy
12         efficiency, and the environment, and articulating these policies to our
13         external audiences.
14   Q 3   Please summarize your educational and professional background.
15   A 3   I graduated from Washington University in St. Louis in 1972 with a Bachelor
16         of Arts and from McGeorge School of Law, Sacramento in 1980 with a Juris
17         Doctor degree. I am a member of the State Bar of California.
18             I joined Pacific Gas and Electric Company in 1997 as Vice President,
19         Governmental Relations and Vice President, Governmental Relations at
20         PG&E Corporation. In 1998, I was promoted to Senior Vice President,
21         Public Affairs at Pacific Gas and Electric Company and in 2000 I was
22         promoted to the same position at PG&E Corporation. I assumed my current
23         title in 2005.
24             Prior to joining PG&E, from 1986 to 1997, I was Co-Founder and
25         Principal of Morse, Richard, Weisenmiller and Associates, Inc. From 1983
26         to 1986, I was Vice President of Independent Power Corporation. From
27         1982 to 1983, I was a Special Assistant, Deputy Legal Affairs Secretary in
28         the Office of the Governor, state of California. From 1979 to 1982, I was an
29         Advisor to the Chairman at the California Energy Commission. From 1978
30         to 1979, I worked as Deputy Assistant For Science and Technology in the
31         Office of the Governor, state of California. Prior to 1978 I worked at NASA.
32   Q 4   What is the purpose of your testimony?
33   A 4   I am sponsoring Chapters 2, “Policy.”


                                           DDR-1
1   Q 5   Does this conclude your statement of qualifications?
2   A 5   Yes, it does.




                                        DDR-2
 1              PACIFIC GAS AND ELECTRIC COMPANY
 2         STATEMENT OF QUALIFICATIONS OF TODD STRAUSS

 3   Q 1   Please state your name and business address.
 4   A 1   My name is Todd Strauss, and my business address is Pacific Gas and
 5         Electric Company, 245 Market Street, San Francisco, California.
 6   Q 2   Briefly describe your responsibilities at Pacific Gas and Electric Company.
 7   A 2   I hold the position of director of Market Assessment and Quantitative
 8         Analysis. I support the electric procurement function by supervising
 9         valuation modeling, portfolio analysis, and market assessment.
10   Q 3   Please summarize your educational and professional background.
11   A 3   I received my Bachelor of Science degree in Mathematics from the
12         Massachusetts Institute of Technology. I hold a Ph.D. in Industrial
13         Engineering and Operations Research from the University of California at
14         Berkeley.
15             I have worked as an Assistant Professor at the Yale School of
16         Management, a Principal at the consulting firm PHB Hagler Bailly, and
17         director of Quantitative Analysis at an affiliate company of Pacific Gas and
18         Electric Company.
19             In 2003, I joined PG&E as director of Quantitative Analysis.
20   Q 4   What is the purpose of your testimony?
21   A 4   I am sponsoring Chapter 3, Section E, “Proposed Prices for As-delivered
22         Capacity Under Existing QF Contracts, and for Capacity Under New QF
23         Contracts,” and Appendix B, Section B, “As-delivered Capacity
24         Overpayment.”
25   Q 5   Does this conclude your statement of qualifications?
26   A 5   Yes, it does.




                                           TS-1
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

MRW & ASSOCIATES, INC.                                       CALIFORNIA ENERGY MARKETS
1999 HARRISON ST, STE 1440                                   517-B POTRERO AVE
OAKLAND CA 94612                                             SAN FRANCISCO CA 94110
 Email: mrw@mrwassoc.com                                      FOR: CALIFORNIA ENERGY MARKETS
 Status: INFORMATION                                          Email: cem@newsdata.com
                                                              Status: INFORMATION

Dan Adler                                                    CASE ADMINISTRATION
CALIF PUBLIC UTILITIES COMMISSION                            SOUTHERN CALIFORNIA EDISON COMPANY
DIVISION OF STRATEGIC PLANNING                               2244 WALNUT GROVE AVE, RM. 370
505 VAN NESS AVE RM 5119                                     ROSEMEAD CA 91770
SAN FRANCISCO CA 94102-3214                                   FOR: Southern California Edison Company
 Email: dpa@cpuc.ca.gov                                       Email: case.admin@sce.com
 Status: STATE-SERVICE                                        Status: INFORMATION

MICHAEL ALCANTAR ATTORNEY                                    GARY L. ALLEN
ALCANTAR & KAHL LLP                                          SOUTHERN CALIFORNIA EDISON
1300 SW FIFTH AVE, STE 1750                                  2244 WALNUT GROVE AVE
PORTLAND OR 97201                                            ROSEMEAD CA 91770
 FOR: CAC                                                     Email: gary.allen@sce.com
 Email: mpa@a-klaw.com                                        Status: INFORMATION
 Status: APPEARANCE

ROD AOKI ATTORNEY                                            E. JESUS ARREDONDO DIRECTOR, REGULATORY AND
ALCANTAR & KAHL, LLP                                         GOVERNMENTAL
120 MONTGOMERY ST, STE 2200                                  NRG ENERGY, INC.
SAN FRANCISCO CA 94104                                       3741 GRESHAM LANE
 FOR: ENERGY PRODUCERS & USERS COALITION                     SACRAMENTO CA 95835
 Email: rsa@a-klaw.com                                        FOR: NRG ENERGY, INC.
 Status: INFORMATION                                          Email: jesus.arredondo@nrgenergy.com
                                                              Status: INFORMATION

Philippe Auclair                                             DEVRA BACHRACH
CALIF PUBLIC UTILITIES COMMISSION                            NATURAL RESOURCES DEFENSE COUNCIL
EXECUTIVE DIVISION                                           111 SUTTER ST, 20TH FLR
505 VAN NESS AVE RM 5218                                     SAN FRANCISCO CA 94104
SAN FRANCISCO CA 94102-3214                                   FOR: Natural Resources Defense Council
 Email: pha@cpuc.ca.gov                                       Email: dbachrach@nrdc.org
 Status: STATE-SERVICE                                        Status: APPEARANCE

GEORGETTA J. BAKER                                           BARBARA R. BARKOVICH
SEMPRA ENERGY                                                BARKOVICH & YAP, INC.
101 ASH ST, HQ 13                                            44810 ROSEWOOD TERRACE
SAN DIEGO CA 92101                                           MENDOCINO CA 95460
 FOR: San Diego Gas & Electric Company and Southern           FOR: California Large Energy Consumers Association
         California Gas Company                               Email: brbarkovich@earthlink.net
 Email: gbaker@sempra.com                                     Status: APPEARANCE
 Status: APPEARANCE

TOM BEACH                                                    ROGER A. BERLINER ATTORNEY
CROSSBORDER ENERGY                                           MANATT, PHELPS & PHILLIPS, LLP
2560 NINTH ST, STE 316                                       700 12TH ST, NW
BERKELEY CA 94710                                            WASHINGTON DC 20005
 FOR: California Cogeneration Council                         FOR: County of Los Angeles
 Email: tomb@crossborderenergy.com                            Email: rberliner@manatt.com
 Status: APPEARANCE                                           Status: APPEARANCE




                                                 Page 1 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                   CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                           Total number of addressees: 155

WILLIAM H. BOOTH ATTORNEY                                     KAREN BOWEN ATTORNEY
LAW OFFICE OF WILLIAM H. BOOTH                                WHITE & CASE, LLP
1500 NEWELL AVE, 5TH FLR                                      3 EMBARCADERO CENTER, 22ND FLR
WALNUT CREEK CA 94596                                         SAN FRANCISCO CA 94111
 FOR: California Large Energy Consumers Association            FOR: California Cogeneration Council
 Email: wbooth@booth-law.com                                   Email: kbowen@whitecase.com
 Status: APPEARANCE                                            Status: APPEARANCE

MICHAEL E. BOYD PRESIDENT                                     ANDREW B. BROWN ATTORNEY
CALIFORNIANS FOR RENEWABLE ENERGY, INC.                       ELLISON, SCHNEIDER & HARRIS, LLP
5439 SOQUEL DRIVE                                             2015 H ST
SOQUEL CA 95073                                               SACRAMENTO CA 95814-3109
 FOR: CALIFORNIANS FOR RENEWABLE ENERGY, INC.                  FOR: DEPARTMENT OF GENERAL SERVICES
 Email: michaeledwardboyd@sbcglobal.net                        Email: abb@eslawfirm.com
 Status: APPEARANCE                                            Status: INFORMATION

LYNNE BROWN                                                   MARGARET D. BROWN ATTORNEY
CALIFORNIANS FOR RENEWABLE ENERGY, INC.                       PACIFIC GAS AND ELECTRIC COMPANY
24 HARBOR ROAD                                                PO BOX 7442
SAN FRANCISCO CA 94124                                        SAN FRANCISCO CA 94120-7442
 FOR: CALIFORNIANS FOR RENEWABLE ENERGY, INC.                  Email: mdbk@pge.com
 Email: l_brown123@hotmail.com                                 Status: INFORMATION
 Status: INFORMATION

MAURICE CAMPBELL MEMBER                                       DAN L. CARROLL ATTORNEY
CALIFORNIANS FOR RENEWABLE ENERGY, INC.                       DOWNEY BRAND LLP
1100 BRUSSELS ST.                                             555 CAPITOL MALL, 10TH FLR
SAN FRANCISCO CA 94134                                        SACRAMENTO CA 95814
 FOR: CALIFORNIANS FOR RENEWABLE ENERGY, INC.                  Email: dcarroll@downeybrand.com
 Email: mecsoft@pacbell.net                                    Status: INFORMATION
 Status: INFORMATION

CENTRAL FILES                                                 Theresa Cho
SAN DIEGO GAS & ELECTRIC                                      CALIF PUBLIC UTILITIES COMMISSION
CP31-E                                                        EXECUTIVE DIVISION
8330 CENTURY PARK COURT                                       505 VAN NESS AVE RM 5207
SAN DIEGO CA 92123-1530                                       SAN FRANCISCO CA 94102-3214
 FOR: SAN DIEGO GAS & ELECTRIC                                 Email: tcx@cpuc.ca.gov
 Email: centralfiles@semprautilities.com                       Status: STATE-SERVICE
 Status: INFORMATION

HOWARD W. CHOY DIVISION MANAGER                               JANET COMBS ATTORNEY
LOS ANGELES COUNTY ISD, FACILITIES OPERA                      SOUTHERN CALIFORNIA EDISON COMPANY
1100 NORTH EASTERN AVE                                        2244 WALNUT GROVE AVE
LOS ANGELES CA 90063                                          ROSEMEAD CA 91770
 FOR: LOS ANGELES COUNTY ISD. FACILITIES                       Email: janet.combs@sce.com
         OPERATION SERVICE                                     Status: APPEARANCE
 Email: hchoy@isd.co.la.ca.us
 Status: INFORMATION

BRIAN T. CRAGG ATTORNEY                                       DOUG DAVIE
GOODIN MACBRIDE SQUERI RITCHIE & DAY LLP                      DAVIE CONSULTING, LLC
505 SANSOME ST, STE 900                                       3390 BEATTY DRIVE
SAN FRANCISCO CA 94111                                        EL DORADO HILLS CA 95762
 Email: bcragg@gmssr.com                                       Email: dougdpucmail@yahoo.com
 Status: INFORMATION                                           Status: INFORMATION




                                                   Page 2 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

Regina DeAngelis                                             Karen A Degannes
CALIF PUBLIC UTILITIES COMMISSION                            CALIF PUBLIC UTILITIES COMMISSION
LEGAL DIVISION                                               ENGINEERING, ENVIRONMENTAL STUDIES,
505 VAN NESS AVE RM 4107                                     CUSTOMER SERVICE
SAN FRANCISCO CA 94102-3214                                  505 VAN NESS AVE AREA 4-A
 Email: rmd@cpuc.ca.gov                                      SAN FRANCISCO CA 94102-3214
 Status: APPEARANCE                                           Email: kdg@cpuc.ca.gov
                                                              Status: STATE-SERVICE

CHRIS ANN DICKERSON, PHD                                     LOS ANGELES DOCKET OFFICE
FREEMAN, SULLIVAN & CO.                                      CALIFORNIA PUBLIC UTILITIES COMMISSION
100 SPEAR ST., 17/F                                          320 W. 4TH ST, STE 500
SAN FRANCISCO CA 94105                                       LOS ANGELES CA 90013
 FOR: FREEMAN, SULLIVAN & CO.                                 Email: LAdocket@cpuc.ca.gov
 Email: dickerson06@fscgroup.com                              Status: STATE-SERVICE
 Status: INFORMATION

JANET DOYLE                                                  Shannon Eddy
KRAMER JUNCTION COMPANY                                      CALIF PUBLIC UTILITIES COMMISSION
1636 AJAX LANE                                               EXECUTIVE DIVISION
EVERGREEN CO 80439                                           505 VAN NESS AVE RM 4102
 Email: jheckdoyle@aol.com                                   SAN FRANCISCO CA 94102-3214
 Status: INFORMATION                                          Email: sed@cpuc.ca.gov
                                                              Status: STATE-SERVICE

Marshal B. Enderby                                           RICHARD M. ESTEVES
CALIF PUBLIC UTILITIES COMMISSION                            SESCO, INC.
ENERGY COST OF SERVICE & NATURAL GAS BRANCH                  77 YACHT CLUB DRIVE, STE 1000
505 VAN NESS AVE RM 4205                                     LAKE HOPATCONG NJ 7849
SAN FRANCISCO CA 94102-3214                                   FOR: SESCO INC.
 FOR: ORA                                                     Email: sesco@optonline.net
 Email: mbe@cpuc.ca.gov                                       Status: INFORMATION
 Status: STATE-SERVICE

ANNE FALCON                                                  DIANE I. FELLMAN
EES CONSULTING, INC.                                         LAW OFFICE OF DIANE I. FELLMAN
570 KIRKLAND AVE                                             234 VAN NESS AVE
KIRLAND WA 98033                                             SAN FRANCISCO CA 94102
 Email: rfp@eesconsulting.com                                 Email: diane_fellman@fpl.com
 Status: INFORMATION                                          Status: INFORMATION

LAW DEPARTMENT FILE ROOM                                     DAVID H. FLEISIG ATTORNEY
PACIFIC GAS AND ELECTRIC COMPANY                             PACIFIC GAS AND ELECTRIC COMPANY
PO BOX 7442                                                  77 BEALE ST.
SAN FRANCISCO CA 94120-7442                                  SAN FRANCISCO CA 94120
 Email: cpuccases@pge.com                                     FOR: Pacific Gas and Electric Company
 Status: INFORMATION                                          Email: dhf5@pge.com
                                                              Status: APPEARANCE

MICHEL PETER FLORIO ATTORNEY                                 MATTHEW FREEDMAN ATTORNEY
THE UTILITY REFORM NETWORK (TURN)                            THE UTILITY REFORM NETWORK
711 VAN NESS AVE, STE 350                                    711 VAN NESS AVE, STE 350
SAN FRANCISCO CA 94102                                       SAN FRANCISCO CA 94102
 FOR: TURN                                                    FOR: THE UTILITY REFORM NETWORK
 Email: mflorio@turn.org                                      Email: freedman@turn.org
 Status: APPEARANCE                                           Status: INFORMATION




                                                 Page 3 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

JOHN C. GABRIELLI                                            JOHN GALLOWAY
GABRIELLI LAW OFFICE                                         UNION OF CONCERNED SCIENTISTS
430 D ST                                                     2397 SHATTUCK AVE, STE 203
DAVIS CA 95616                                               BERKELEY CA 94704
 FOR: GABRIELLI LAW OFFICE                                    FOR: UCS
 Email: gumbrelli@cs.com                                      Email: jgalloway@ucsusa.org
 Status: INFORMATION                                          Status: APPEARANCE

MARY A. GANDESBERY ATTORNEY                                  LAURA GENAO ATTORNEY
PACIFIC GAS AND ELECTRIC COMPANY                             SOUTHERN CALIFORNIA EDISON COMPANY
77 BEALE ST, B30A                                            2244 WALNUT GROVE AVE
SAN FRANCISCO CA 94105                                       ROSEMEAD CA 91770
 FOR: Pacific Gas & Electric Company                          Email: laura.genao@sce.com
 Email: magq@pge.com                                          Status: INFORMATION
 Status: APPEARANCE

ROBERT B. GEX ATTORNEY,                                      JEFFREY P. GRAY ATTORNEY
DAVIS WRIGHT TREMAINE LLP                                    DAVIS WRIGHT TREMAINE LLP
ONE EMBARCADERO CENTER, STE 600                              ONE EMBARCADERO CENTER, STE 600
SAN FRANCISCO CA 94111-3611                                  SAN FRANCISCO CA 94111
 Email: robertgex@dwt.com                                     Email: jeffgray@dwt.com
 Status: INFORMATION                                          Status: INFORMATION

STEVEN A. GREENBERG                                          JOHN E. GREENHALGH
DISTRIBUTED ENERGY STRATEGIES                                NEW ERA ENERGY, INC.
4100 ORCHARD CANYON LANE                                     PO BOX 5984
VACAVILLE CA 95688                                           WILLIAMSBURG VA 23188
 FOR: DISTRIBUTED ENERGY STRATEGIES                           Email: jack@jackgreenhalgh.com
 Email: steveng@destrategies.com                              Status: INFORMATION
 Status: INFORMATION

STEVEN F. GREENWALD ATTORNEY                                 DANIEL V. GULINO
DAVIS WRIGHT TREMAINE, LLP                                   RIDGEWOOD POWER MANAGEMENT, LLC
ONE EMBARCADERO CENTER, 6TH FLR                              947 LINWOOD AVE
SAN FRANCISCO CA 94111                                       RIDGEWOOD NJ 7450
 Email: stevegreenwald@dwt.com                                FOR: RIDGEWOOD POWER MANAGEMENT, LLC
 Status: INFORMATION                                          Email: dgulino@ridgewoodpower.com
                                                              Status: INFORMATION

Julie Halligan                                               PETER W. HANSCHEN
CALIF PUBLIC UTILITIES COMMISSION                            MORRISON & FOERSTER, LLP
DIVISION OF ADMINISTRATIVE LAW JUDGES                        101 YGNACIO VALLEY ROAD, STE 450
505 VAN NESS AVE RM 5101                                     WALNUT CREEK CA 94596-8130
SAN FRANCISCO CA 94102-3214                                   Email: phanschen@mofo.com
 Email: jmh@cpuc.ca.gov                                       Status: INFORMATION
 Status: STATE-SERVICE

MARK HARRER                                                  TIM HEMIG DIRECTOR
56 ST. TIMOTHY CT.                                           REGIONAL ENVIRONMENTAL BUSINESS NRG ENER
DANVILLE CA 94526                                            4600 CARLSBAD BLVD.
 Email: mhharrer@sbcglobal.net                               CARLSBAD CA 92008
 Status: INFORMATION                                          FOR: REGIONAL ENVIRONMENTAL BUSINESS NRG
                                                                      ENERGY
                                                              Email: tim.hemig@nrgenergy.com
                                                              Status: INFORMATION




                                                 Page 4 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

CHRISTOPHER HILEN ATTORNEY                                   Donna J Hines
DAVIS WRIGHT TREMAINE, LLP                                   CALIF PUBLIC UTILITIES COMMISSION
ONE EMBARCADERO CENTER, STE 600                              ELECTRICITY RESOURCES & PRICING BRANCH
SAN FRANCISCO CA 94111                                       505 VAN NESS AVE RM 4102
 Email: chrishilen@dwt.com                                   SAN FRANCISCO CA 94102-3214
 Status: INFORMATION                                          Email: djh@cpuc.ca.gov
                                                              Status: STATE-SERVICE

PATRICK HOLLEY                                               DAVID HOWARTH
COVANTA ENERGY CORPORATION                                   MRW & ASSOCIATES, INC.
3085 CROSSROADS DR.                                          1999 HARRISON ST, STE 1440
REDDING CA 96003                                             OAKLAND CA 94612
 FOR: COVANTA ENERGY CORP                                     Email: mrw@mrwassoc.com
 Email: pholley@covantaenergy.com                             Status: INFORMATION
 Status: INFORMATION

DAVID L. HUARD ATTORNEY                                      MARK R. HUFFMAN ATTORNEY
MANATT, PHELPS & PHILLIPS, LLP                               PACIFIC GAS AND ELECTRIC COMPANY
11355 WEST OLYMPIC BLVD                                      77 BEALE ST, MC B30A,RM 3133
LOS ANGELES CA 90064                                         SAN FRANCISCO CA 94105
 FOR: County of Los Angeles                                   FOR: PACIFIC GAS AND ELECTRIC COMPANY
 Email: dhuard@manatt.com                                     Email: mrh2@pge.com
 Status: APPEARANCE                                           Status: INFORMATION

ERIC J. ISKEN ATTORNEY                                       MICHAEL JASKE
SOUTHERN CALIFORNIA EDISON COMPANY                           CALIFORNIA ENERGY COMMISSION
2244 WALNUT GROVE AVE                                        1516 9TH ST, MS-500
ROSEMEAD CA 91770                                            SACRAMENTO CA 95814
 Email: j.eric.isken@sce.com                                  Email: mjaske@energy.state.ca.us
 Status: INFORMATION                                          Status: STATE-SERVICE

MARC D. JOSEPH ATTORNEY                                      EVELYN KAHL ATTORNEY
ADAMS, BROADWELL, JOSEPH & CARDOZO                           ALCANTAR & KAHL, LLP
601 GATEWAY BLVD., STE. 1000                                 120 MONTGOMERY ST, STE 2200
SOUTH SAN FRANCISCO CA 94080                                 SAN FRANCISCO CA 94104
 FOR: ADAMS BROADWELL JOSEPH & CARDOZO                        FOR: Chevron Texaco
 Email: mdjoseph@adamsbroadwell.com                           Email: ek@a-klaw.com
 Status: INFORMATION                                          Status: APPEARANCE

JOSEPH M. KARP ATTORNEY                                      CURTIS KEBLER
WHITE & CASE LLP                                             GOLDMAN, SACHS & CO.
3 EMBARCADERO CENTER, 22ND FLR                               2121 AVE OF THE STARS
SAN FRANCISCO CA 94111                                       LOS ANGELES CA 90067
 FOR: California Cogeneration Council & California Wind       FOR: GOLDMAN, SACHS & CO.
         Energy Association                                   Email: curtis.kebler@gs.com
 Email: jkarp@whitecase.com                                   Status: INFORMATION
 Status: APPEARANCE

RANDALL W. KEEN ATTORNEY                                     WENDY KEILANIA REGULATORY CASE MANAGER
MANATT PHELPS & PHILLIPS, LLP                                SAN DIEGO GAS & ELECTRIC COMPANY
11355 WEST OLYMPIC BLVD.                                     CP32D
LOS ANGELES CA 90064                                         8330 CENTURY PARK CT.
 FOR: MANATT PHELPS & PHILLIPS, LLP                          SAN DIEGO CA 92123
 Email: pucservice@manatt.com                                 Email: WKeilani@semprautilities.com
 Status: INFORMATION                                          Status: INFORMATION




                                                 Page 5 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                         Total number of addressees: 155

STEVEN KELLY                                                 DOUGLAS K. KERNER ATTORNEY
INDEPENDENT ENERGY PRODUCERS ASSN                            ELLISON, SCHNEIDER & HARRIS LLP
1215 K ST, STE 900                                           2015 H ST
SACRAMENTO CA 95814                                          SACRAMENTO CA 95814
 FOR: Independent Energy Producers Assn.                      FOR: Independent Energy Producers Association
 Email: steven@iepa.com                                       Email: dkk@eslawfirm.com
 Status: APPEARANCE                                           Status: APPEARANCE

CHRIS KING                                                   Robert Kinosian
CALIFORNIA CONSUMER EMPOWERMENT                              CALIF PUBLIC UTILITIES COMMISSION
ONE TWIN DOLPHIN DRIVE                                       ELECTRICITY RESOURCES & PRICING BRANCH
REDWOOD CITY CA 94065                                        505 VAN NESS AVE RM 4205
 Email: chris@emeter.com                                     SAN FRANCISCO CA 94102-3214
 Status: INFORMATION                                          Email: gig@cpuc.ca.gov
                                                              Status: STATE-SERVICE

JOSEPH KLOBERDANZ                                            MARC KOLB
SAN DIEGO GAS & ELECTRIC COMPANY                             PACIFIC GAS AND ELECTRIC COMPANY
8330 CENTURY PARK COURT                                      77 BEALE ST, B918
SAN DIEGO CA 92123                                           SAN FRANCISCO CA 94105
 Email: jkloberdanz@semprautilities.com                       Email: mekd@pge.com
 Status: INFORMATION                                          Status: INFORMATION

EDWARD V. KURZ ATTORNEY                                      PAUL C. LACOURCIERE ATTORNEY
PACIFIC GAS AND ELECTRIC COMPANY                             THELEN REID & PRIEST LLP
77 BEALE ST                                                  101 SECOND ST, STE 1800
SAN FRANCISCO CA 94105                                       SAN FRANCISCO CA 94105
 FOR: Pacific Gas and Electric (Replacing David Fleisi who    FOR: THELEN REID & PRIEST LLP
         is currently on the service list                     Email: placourciere@thelenreid.com
 Email: evk1@pge.com                                          Status: INFORMATION
 Status: APPEARANCE

Peter Lai                                                    RICHARD LAUCKHART
CALIF PUBLIC UTILITIES COMMISSION                            HENWOOD ENERGY SERVICES, INC.
NATURAL GAS, ENERGY EFFICIENCY AND RESOURCE                  2379 GATEWAY OAKS DRIVE, STE 200
ADVISORY                                                     SACRAMENTO CA 95833
320 WEST 4TH ST STE 500                                       FOR: HENWOOD ENERGY SERVICES, INC.
LOS ANGELES CA 90013                                          Email: rlauckhart@henwoodenergy.com
 Email: ppl@cpuc.ca.gov                                       Status: INFORMATION
 Status: STATE-SERVICE

STEVEN A. LEFTON VP POWER PLANT PROJECTS                     MAUREEN LENNON
APTECH ENGINEERING SERVICES INC.                             WHITE & CASE
1253 REAMWOOD AVE                                            633 WEST 5TH ST, 19TH FLR
SUNNYVALE CA 94089                                           LOS ANGELES CA 90071
 FOR: APTECH ENGINEERING SERVICES INC.                        FOR: California Cogeneration Council
 Email: slefton@aptecheng.com                                 Email: mlennon@whitecase.com
 Status: INFORMATION                                          Status: APPEARANCE

JOHN W. LESLIE ATTORNEY                                      DONALD C. LIDDELL, P.C.
LUCE, FORWARD, HAMILTON & SCRIPPS, LLP                       DOUGLASS & LIDDELL
11988 EL CAMINO REAL, STE 200                                2928 2ND AVE
SAN DIEGO CA 92130                                           SAN DIEGO CA 92103
 FOR: LUCE, FORWARD, HAMILTON & SCRIPPS, LLP                  Email: liddell@energyattorney.com
 Email: jleslie@luce.com                                      Status: INFORMATION
 Status: INFORMATION




                                                  Page 6 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                        Downloaded August 31, 2005, last updated on August 29, 2005
   Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
          ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                 CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                       Total number of addressees: 155

KAREN LINDH                                                 Steve Linsey
LINDH & ASSOCIATES                                          CALIF PUBLIC UTILITIES COMMISSION
PMB 119                                                     ELECTRICITY RESOURCES & PRICING BRANCH
7909 WALERGA ROAD, NO. 112                                  505 VAN NESS AVE AREA 4-D
ANTELOPE CA 95843                                           SAN FRANCISCO CA 94102-3214
 Email: karen@klindh.com                                     FOR: ORA
 Status: INFORMATION                                         Email: car@cpuc.ca.gov
                                                             Status: STATE-SERVICE

GRACE LIVINGSTON-NUNLEY                                     BARRY LOVELL
PACIFIC GAS AND ELECTRIC COMPANY                            BERRY PETROLEUM COMPANY
77 BEALE ST, MAIL CODE B9A                                  5201 TRUXTUN AVE., STE 300
SAN FRANCISCO CA 94105                                      BAKERSFIED CA 93309
 Email: gxl2@pge.com                                         FOR: BERRY PETROLEUM COMPANY
 Status: INFORMATION                                         Email: bjl@bry.com
                                                             Status: INFORMATION

ED LUCHA                                                    ALEXANDRE B. MAKLER
PACIFIC GAS AND ELECTRIC COMPANY                            CALPINE CORPORATION
77 BEALE ST, MAIL CODE B9A                                  4160 DUBLIN BLVD.
SAN FRANCISCO CA 94105                                      DUBLIN CA 94568-1749
 Email: ell5@pge.com                                         FOR: CALPINE CORPORATION
 Status: INFORMATION                                         Email: alexm@calpine.com
                                                             Status: INFORMATION

WILLIAM B. MARCUS                                           CHRISTOPHER J. MAYER
JBS ENERGY, INC.                                            MODESTO IRRIGATION DISTRICT
311 D ST, STE A                                             PO BOX 4060
WEST SACRAMENTO CA 95605                                    MODESTO CA 95352-4060
 FOR: TURN                                                   FOR: MODESTO IRRIGATION DISTRICT
 Email: bill@jbsenergy.com.                                  Email: chrism@mid.org
 Status: APPEARANCE                                          Status: INFORMATION

RICHARD MCCANN                                              Wade McCartney
M.CUBED                                                     CALIF PUBLIC UTILITIES COMMISSION
2655 PORTAGE BAY ROAD, STE 3                                NATURAL GAS, ENERGY EFFICIENCY AND RESOURCE
DAVIS CA 95616                                              ADVISORY
 Email: rmccann@umich.edu                                   770 L ST, STE 1050
 Status: INFORMATION                                        SACRAMENTO CA 95814
                                                             Email: wsm@cpuc.ca.gov
                                                             Status: STATE-SERVICE

LIZBETH MCDANNEL                                            PATRICK MCDONNELL
2244 WALNUT GROVE AVE., QUAD 4D                             AGLAND ENERGY SERVICES, INC.
ROSEMEAD CA 91770                                           2000 NICASIO VALLEY RD.
 Email: lizbeth.mcdannel@sce.com                            NICASIO CA 94946
 Status: INFORMATION                                         FOR: Agland Energy Services
                                                             Email: pcmcdonnell@earthlink.net
                                                             Status: APPEARANCE

TANDY MCMANNES                                              KEVIN R. MCSPADDEN ATTORNEY
SOLAR THERMAL ELECTRIC ALLIANCE                             MILBANK,TWEED,HADLEY&MCCLOY LLP
2938 CROWNVIEW DRIVE                                        601 SOUTH FIGUEROA ST, 30TH FLR
RANCHO PALOS VERDES CA 90275                                LOS ANGELES CA 90068
 Email: mcmannes@aol.com                                     Email: kmcspadden@milbank.com
 Status: INFORMATION                                         Status: INFORMATION




                                                Page 7 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

BRADLEY MEISTER                                              KEITH W. MELVILLE ATTORNEY
CALIFORNIA ENERGY COMMISSION                                 SEMPRA ENERGY
1516 9TH ST, MS-26                                           101 ASH ST
SACRAMENTO CA 95814                                          SAN DIEGO CA 92101-3017
 FOR: California Energy Commission                            Email: kmelville@sempra.com
 Email: bmeister@energy.state.ca.us                           Status: INFORMATION
 Status: STATE-SERVICE

MARY ANN MILLER ELECTRICITY ANALYSIS OFFICE                  JASMIN MILLES
CALIFORNIA ENERGY COMMISSION                                 VERIZON CALIFORNIA INC
1516 9TH ST, MS 20                                           CA501LB
SACRAMENTO CA 96814-5512                                     112 S. LAKE LINDERO CANYON ROAD
 FOR: CALIFORNIA ENERGY COMMISSION                           THOUSAND OAKS CA 91362
 Email: mmiller@energy.state.ca.us                            Email: jasmin.e.milles@verizon.com
 Status: STATE-SERVICE                                        Status: INFORMATION

WILLIAM A. MONSEN                                            GREGG MORRIS
MRW & ASSOCIATES, INC.                                       GREEN POWER INSTITUTE
1999 HARRISON ST, STE 1440                                   2039 SHATTUCK AVE., STE 402
OAKLAND CA 94612                                             BERKELEY CA 94704
 Email: mrw@mrwassoc.com                                      Email: gmorris@emf.net
 Status: INFORMATION                                          Status: APPEARANCE

SARA STECK MYERS ATTORNEY                                    ALAN NOGEE
LAW OFFICES OF SARA STECK MYERS                              UNION OF CONCERNED SCIENTISTS
122 - 28TH AVE                                               2 BRATTLE SQUARE
SAN FRANCISCO CA 94121                                       CAMBRIDGE MA 2238
 FOR: Center for Energy Efficiency and Renewable              Email: anogee@ucsusa.org
         Technologies (CEERT)                                 Status: APPEARANCE
 Email: ssmyers@att.net
 Status: APPEARANCE

RICK NOGER                                                   Noel Obiora
PRAXAIR PLAINFIELD, INC.                                     CALIF PUBLIC UTILITIES COMMISSION
2678 BISHOP DRIVE                                            LEGAL DIVISION
SAN RAMON CA 94583                                           505 VAN NESS AVE RM 4107
 FOR: PRAXAIR PLAINFIELD, INC.                               SAN FRANCISCO CA 94102-3214
 Email: rick_noger@praxair.com                                Email: nao@cpuc.ca.gov
 Status: APPEARANCE                                           Status: INFORMATION

REN ORENS                                                    BERJ K. PARSEGHIAN ATTORNEY
ENERGY AND ENVIRONMENTAL ECONOMICS                           SOUTHERN CALIFORNIA EDISON COMPANY
353 SACRAMENTO ST., STE 1700                                 2244 WALNUT GROVE AVE
SAN FRANCISCO CA 94111                                       ROSEMEAD CA 91770
 Email: ren@ethree.com                                        FOR: Southern California Edison Company
 Status: INFORMATION                                          Email: berj.parseghian@sce.com
                                                              Status: APPEARANCE

Karen P Paull                                                Marion Peleo
CALIF PUBLIC UTILITIES COMMISSION                            CALIF PUBLIC UTILITIES COMMISSION
LEGAL DIVISION                                               LEGAL DIVISION
505 VAN NESS AVE RM 4300                                     505 VAN NESS AVE RM 4107
SAN FRANCISCO CA 94102-3214                                  SAN FRANCISCO CA 94102-3214
 Email: kpp@cpuc.ca.gov                                       FOR: ORA
 Status: APPEARANCE                                           Email: map@cpuc.ca.gov
                                                              Status: APPEARANCE




                                                 Page 8 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

JANIS C. PEPPER                                              JACK PIGOTT
CLEAN POWER MARKETS, INC.                                    CALPINE CORPORATION
418 BENVENUE AVE                                             4160 DUBLIN BLVD.
LOS ALTOS CA 94024                                           DUBLIN CA 94568
 FOR: CLEAN POWER MARKETS, INC.                               Email: jackp@calpine.com
 Email: pepper@cleanpowermarkets.com                          Status: INFORMATION
 Status: INFORMATION

WILLIAM E. POWERS                                            SNULLER PRICE
POWERS ENGINEERING                                           ENERGY AND ENVIRONMENTAL ECONOMICS
4452 PARK BLVD., STE. 209                                    353 SACRAMENTO ST., STE. 1700
SAN DIEGO CA 92116                                           SAN FRANCISCO CA 94111
 FOR: POWERS ENGINEERING                                      Email: snuller@ethree.com
 Email: bpowers@powersengineering.com                         Status: STATE-SERVICE
 Status: INFORMATION

Terrie D Prosper                                             ALAN PURVES
CALIF PUBLIC UTILITIES COMMISSION                            CALIFORNIA LANDFILL GAS COALITION
EXECUTIVE DIVISION                                           5717 BRISA ST
505 VAN NESS AVE RM 5301                                     LIVERMORE CA 94550
SAN FRANCISCO CA 94102-3214                                   FOR: California Landfill Gas Coalition
 Email: tdp@cpuc.ca.gov                                       Email: purves@grsllc.net
 Status: STATE-SERVICE                                        Status: APPEARANCE

NANCY RADER                                                  W. PHILLIP REESE
CALIFORNIA WIND ENERGY ASSOCIATION                           CALIFORNIA BIOMASS ENERGY ALLIANCE, LLC
1198 KEITH AVE                                               PO BOX 8
BERKELEY CA 94708                                            SOMIS CA 93066
 FOR: California Wind Energy Association                      FOR: CBEA
 Email: nrader@calwea.org                                     Email: phil@reesechambers.com
 Status: APPEARANCE                                           Status: APPEARANCE

DAVID REYNOLDS                                               GRANT A. ROSENBLUM ATTORNEY
ASPEN SYSTEMS CORPORATION                                    CALIFORNIA INDEPENDENT SYSTEM OPERATOR
5802 BALFOR ROAD                                             151 BLUE RAVINE ROAD
ROCKLIN CA 95765                                             FOLSOM CA 95630
 FOR: ASPEN SYSTEMS CORP                                      FOR: California Independent System Operator
 Email: dreynolds@aspensys.com                                Email: grosenblum@caiso.com
 Status: INFORMATION                                          Status: APPEARANCE

JAMES ROSS                                                   ROBERT SARVEY TREASURER CARE
RCS INC.                                                     CALIFORNIANS FOR RENEWABLE ENERGY, INC.
500 CHESTERFIELD CENTER, STE 320                             501 W. GRANTLINE RD
CHESTERFIELD MO 63017                                        TRACY CA 95376
 FOR: Midway Sunset Cogeneration                              FOR: CALIFORNIANS FOR RENEWABLE ENERGY, INC.
 Email: jimross@r-c-s-inc.com                                 Email: sarveybob@aol.com
 Status: APPEARANCE                                           Status: INFORMATION

DAVID SAUL                                                   STEVEN S. SCHLEIMER
SOLEL, INC.                                                  CALPINE CORPORATION
439 PELICAN BAY COURT                                        4160 DUBLIN BLVD.
HENDERSON NV 89012                                           DUBLIN CA 94568
 FOR: SOLEL, INC.                                             Email: sschleimer@calpine.com
 Email: dsaul@solel.com                                       Status: INFORMATION
 Status: INFORMATION




                                                 Page 9 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

REED V. SCHMIDT                                              DONALD W. SCHOENBECK
BARTLE WELLS ASSOCIATES                                      RCS, INC.
1889 ALCATRAZ AVE                                            900 WASHINGTON ST, STE 780
BERKELEY CA 94703                                            VANCOUVER WA 98660
 Email: rschmidt@bartlewells.com                              Email: dws@r-c-s-inc.com
 Status: INFORMATION                                          Status: INFORMATION

Don Schultz                                                  ROBERT SHAPIRO
CALIF PUBLIC UTILITIES COMMISSION                            CHADBOURNE & PARKE LLP
ELECTRICITY RESOURCES & PRICING BRANCH                       1200 NEW HAMPSHIRE AVE. NW
770 L ST, STE 1050                                           WASHINGTON DC 20036
SACRAMENTO CA 95814                                           Status: INFORMATION
 Email: dks@cpuc.ca.gov
 Status: STATE-SERVICE

NORA SHERIFF ATTORNEY                                        WILLIAM P. SHORT
ALCANTAR & KAHL LLP                                          RIDGEWOOD POWER MANAGEMENT, LLC
120 MONTGOMERY ST, STE 2200                                  947 LINWOOD AVE
SAN FRANCISCO CA 94104                                       RIDGEWOOD NJ 7450
 FOR: EPUC                                                    FOR: RIDGEWOOD POWER MANAGEMENT, LLC
 Email: nes@a-klaw.com                                        Email: bshort@ridgewoodpower.com
 Status: APPEARANCE                                           Status: INFORMATION

TOM SKUPNJAK                                                 SHAWN SMALLWOOD, PH.D.
CPG ENERGY                                                   109 LUZ PLACE
5211 BIRCH GLEN                                              DAVIS CA 95616
RICHMOND TX 77469                                             Email: puma@davis.com
 FOR: Juniper Generation                                      Status: INFORMATION
 Email: toms@i-cpg.com
 Status: APPEARANCE

CAROL A. SMOOTS                                              ANAN H. SOKKER LEGAL ASSISTANT
PERKINS COIE LLP                                             CHADBOURNE & PARKE LLP
607 FOURTEENTH ST, NW, STE 800                               1200 NEW HAMPSHIRE AVE. NW
WASHINGTON DC 20005                                          WASHINGTON DC 20036
 FOR: THELEN REID & PRIEST LLP                                Status: INFORMATION
 Email: csmoots@perkinscoie.com
 Status: INFORMATION

Merideth Sterkel                                             KAREN TERRANOVA
CALIF PUBLIC UTILITIES COMMISSION                            ALCANTAR & KAHL, LLP
NATURAL GAS, ENERGY EFFICIENCY AND RESOURCE                  120 MONTGOMERY ST, STE 2200
ADVISORY                                                     SAN FRANCISCO CA 94104
505 VAN NESS AVE AREA 4-A                                     FOR: COALINGA COGENERATION CO.
SAN FRANCISCO CA 94102-3214                                   Email: filings@a-klaw.com
 Email: mts@cpuc.ca.gov                                       Status: INFORMATION
 Status: STATE-SERVICE

BRIAN THEAKER                                                GEETA O. THOLAN
WILLIAMS POWER COMPANY                                       CALIFORNIA INDEPENDENT SYSTEM OPERATOR
3161 KEN DEREK LANE                                          151 BLUE RAVINE ROAD
PLACERVILLE CA 95667                                         FOLSOM CA 95630
 Email: brian.theaker@williams.com                            FOR: California Independent System Operator
 Status: INFORMATION                                          Email: gtholan@caiso.com
                                                              Status: APPEARANCE




                                                Page 10 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                         Downloaded August 31, 2005, last updated on August 29, 2005
    Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
           ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                  CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                        Total number of addressees: 155

EDWARD J TIEDEMANN                                           ANDREW ULMER ATTORNEY
KRONICK MOSKOVITZ TIEDEMANN AND GIRARD                       SIMPSON PARTNERS, LLP
27TH FLOOR                                                   900 FRONT ST, STE 300
400 CAPITOL MALL                                             SAN FRANCISCO CA 94111
SACRAMENTO CA 95814                                           FOR: California Department of Water Resources
 Email: etiedemann@kmtg.com                                   Email: andrew@simpsonpartners.com
 Status: INFORMATION                                          Status: STATE-SERVICE

ANDREW J. VAN HORN                                           JOY A. WARREN ATTORNEY
VAN HORN CONSULTING                                          MODESTO IRRIGATION DISTRICT
61 MORAGA WAY, STE 1                                         PO BOX 4060
ORINDA CA 94563                                              MODESTO CA 95352-4060
 Email: vhconsult@earthlink.net                               FOR: Modesto Irrigation District
 Status: INFORMATION                                          Email: joyw@mid.org
                                                              Status: APPEARANCE

TORY S. WEBER                                                WILLIAM W. WESTERFIELD III ATTORNEY
SOUTHERN CALIFORNIA EDISON COMPANY                           STOEL RIVES LLP
2131 WALNUT GROVE AVE                                        770 L ST, STE 800
ROSEMEAD CA 91770                                            SACRAMENTO CA 95814
 Email: tory.weber@sce.com                                    Email: wwwesterfield@stoel.com
 Status: INFORMATION                                          Status: INFORMATION

VALERIE J. WINN                                              SHIRLEY WOO ATTORNEY
PACIFIC GAS AND ELECTRIC COMPANY                             PACIFIC GAS AND ELECTRIC COMPANY
77 BEALE ST, B9A                                             77 BEALE ST, B30A
SAN FRANCISCO CA 94105                                       SAN FRANCISCO CA 94105
 FOR: PACIFIC GAS & ELECTRIC COMPANY                          FOR: Pacific Gas and Electric Company
 Email: vjw3@pge.com                                          Email: saw0@pge.com
 Status: INFORMATION                                          Status: APPEARANCE

DON WOOD                                                     VIKKI WOOD PRINCIPAL DEMAND-SIDE SPECIALIST
PACIFIC ENERGY POLICY CENTER                                 SACRAMENTO MUNICIPAL UTILITY DISTRICT
4539 LEE AVE                                                 6301 S ST, MS A103
LA MESA CA 91941                                             SACRAMENTO CA 95618-1899
 Email: dwood8@cox.net                                        Email: vwood@smud.org
 Status: INFORMATION                                          Status: INFORMATION

JAMES WOODRUFF ATTORNEY                                      KEVIN WOODRUFF
SOUTHERN CALIFORNIA EDISON COMPANY                           WOODRUFF EXPERT SERVICES
2244 WALNUT GROVE AVE                                        1100 K ST, STE 204
ROSEMEAD CA 91770                                            SACRAMENTO CA 95814
 FOR: Southern California Edison Company                      FOR: WOODRUFF EXPERT SERVICES
 Email: woodrujb@sce.com                                      Email: kdw@woodruff-expert-services.com
 Status: APPEARANCE                                           Status: INFORMATION

JOY C. YAMAGATA REGULATORY MANAGER                           Amy C Yip-Kikugawa
SAN DIEGO GAS & ELECTRIC COMPANY                             CALIF PUBLIC UTILITIES COMMISSION
8330 CENTURY PARK COURT                                      LEGAL DIVISION
SAN DIEGO CA 92123                                           505 VAN NESS AVE RM 5135
 Email: jyamagata@semprautilities.com                        SAN FRANCISCO CA 94102-3214
 Status: INFORMATION                                          Email: ayk@cpuc.ca.gov
                                                              Status: STATE-SERVICE




                                                Page 11 of 12
THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA SERVICE LIST
                        Downloaded August 31, 2005, last updated on August 29, 2005
   Commissioner Assigned: Michael R. Peevey on April 6, 2004; ALJ Assigned: Carol A Brown on August 12, 2004
          ALJ Assigned: Meg Gottstein on April 6, 2004; ALJ Assigned: Mark S. Wetzell on April 6, 2004
                 CPUC DOCKET NO. R0404003-R0404025 CPUC REV. 08-29-05
                                       Total number of addressees: 155

CARLO ZORZOLI
ENEL NORTH AMERICA, INC.
1 TECH DRIVE, STE 220
ANDOVER MA 1810
 FOR: ENEL NORTH AMERICA, INC.
 Email: carlo.zorzoli@enel.it
 Status: INFORMATION




                                               Page 12 of 12

				
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