IX. Assignment of Proceeding

Michael R. Peevey is the Assigned Commissioner and Anne E. Simon and Burton W. Mattson are the assigned ALJs for this proceeding.

Findings of Fact

1. PG&E proposes accepting bids from eligible renewable resources with delivery points anywhere in California.

2. To the extent reporting problems are now resolved, accepting bids from eligible resources with delivery points anywhere in California casts a wider net for projects and helps IOUs meet program goals.

3. Future transmission needs may be somewhat different for RPS versus non-RPS scenarios, but the essential choice is between RPS with related transmission and other resources with related transmission.

4. IOUs are already engaged in contingency planning, with a margin of safety included in their procurement plans.

5. IOUs must meet APT and IPT requirements (with adjustments for flexible compliance) or face penalties.

6. IOUs' statements demonstrate that they understand that they are ultimately responsible for program success each year and by 2010, subject to flexible compliance rules.

7. The RPS Procurement Plans adopted by the Commission before, and adopted here, provide sufficient opportunity for each IOU to succeed, and larger IPTs or other margins of safety need not be adopted to stimulate IOUs to reach program goals.

8. The year 2010 is the year by which the Commission expects 20% of energy sold to retail end-users to be delivered from eligible renewable resources.

9. GPI and DRA are correct that the full earmarking proposal is an effort to roll back the 2010 RPS date, if not all the way back to 2017, then back to somewhere between 2010 and 2017, and, in combination with flexible compliance for 2010, it pushes the compliance date back to at least 2013.

10. We rejected full earmarking and flexible compliance proposals in 2003, and again in 2005, because we wanted to prevent continuous roll-over of the 25% shortfall, with a utility falling so far behind in its RPS procurement that it jeopardizes attainment of program goals.

11. No evidence supports the assertion that denial of full earmarking and flexible compliance in 2010 will increase the cost of the program; nor that an increase in cost, if any, is material; nor that the increase, if any, is greater than the benefits of the program; nor that the increase, if any, is greater than the incremental benefits of obtaining program goals sooner; while the use of funds above MPR is a matter that should be decided by public officials with that duty after they weigh all competing interests, goals and arguments.

12. PG&E identifies issues that make problematic the signing of contracts by June 30, 2006 for the 2005 solicitation results.

13. Neither PG&E, SCE nor SDG&E, in their role as a utility company, includes any discussion in their RPS Procurement Plans of the utility building renewable generation resource itself.

14. PG&E does not require a bid deposit until a bidder is selected for the short list, while SCE requires a bidder to deposit $25,000 simply to submit a bid.

15. The RPS developers' views of what RPS-eligible renewable resources are likely to be available is at least as important, if not more important, than the utilities' views, because developers are uniquely situated to know whether or not particular resources are worth developing and bidding into a utility solicitation.

16. We have previously noted the dangers of using resource stacks to pre-screen or discourage bids, and stated that we do not want resource stacks to act as hidden weighting factors in bid evaluations.

17. PG&E states a preference for particular resource types in its Plan Protocol, and this may unreasonably discourage bids, or act as a hidden weighting factor.

18. The language proposed by PG&E and SDG&E regarding a change in delivery point upon CAISO market redesign provides protection to the utility, its ratepayers and suppliers.

19. The RPS project evaluation and selection process within the LCBF framework cannot ultimately be reduced to mathematical models and rules that totally eliminate the use of judgment.

20. Several measures can increase the fairness and equity in the bid and selection process, provide the Commission the opportunity to review the use of judgment by the IOUs in the process, increase the transparency of the process, and allow the Commission to take corrective action if necessary including:

a. an IOU report (which can be used as a screening tool) presented to the PRG and the Commission (and available to the service list and the public, with confidential treatment of protected information) that explains each utility's evaluation and selection model, its process, and its decision rationale with respect to each bid, both selected and rejected;

c. inform all stakeholders about the ADR resources available at the Commission;

d. include an equal treatment, fair dealing and good faith performance clause in each RFO; and

e. inform IOUs the Commission will later assess the extent to which each IOU retains extremely broad disclaimer and discretion language in its RFO in a non-compliance enforcement action.

21. IOUs' Plans differ on the thoroughness with which they identify many of the benefits found by the Legislature and this Commission despite our direction that IOU Plans (a) make it clear that these benefits are sought, (b) encourage bidders to state such benefits, if any, in their bids, (c) apply transparent criteria in evaluating such claims.

22. IOU Plans can do a better and more uniform job of specifically stating benefits identified by the Legislature and Commission, and encouraging bidders to address such benefits, if any.

23. Environmental stewardship, as a qualitative factor to consider in assessing RPS bids, includes the environmental impacts of the proposed RPS generation facility on California's water quality, use and water resource management consistent with the Commission's December 15, 2005 Water Action Plan.

24. PG&E's proposal does not permit a bidder to simultaneously submit competing offers to other electricity corporations.

25. A final cutoff for submitting contracts to the Commission for approval can operate as a catalyst to resolving outstanding issues in negotiations, bring swift finality, and result in signed contracts.

26. It is reasonable to grant IOUs, at their option, the ability to treat contracts resulting from the 2006 RPS solicitation as available to demonstrate compliance with their 2006 APT, in the event of deficits greater than 25%, even if the contract is signed after December 31, 2006, as long as the contract is signed within 45 days of Commission adoption of the resolution approving PPAs from the 2006 resolution.

27. The state's RPS goal is not 20% in 2010, but 20% by 2010, and there is nothing that reasonably prohibits the state or electric corporations from seeking to reach this goal before 2010.

28. Individual elements of each IOU's Plan are-or appear to be-unclear, inadequately defined, referenced but not included, inconsistent with other elements, or inconsistent with prior Commission orders.

29. No comments recommend rejecting any specific TOD factors.

30. No TOD benchmarking methodology proposal is sufficiently developed, documented, or explained to be explicitly endorsed or adopted at this time.

31. In December 2005, we considered and rejected Solel's recommendation that SCE's 2006 TOD factors be applied to SCE's 2005 solicitations, and nothing presented here merits reversal of that order.

32. Using PG&E's 2006 TOD factors for its 2005 solicitation, and potentially also requiring bidders to re-calibrate their offer prices to ensure no change to the revenue requirement implicit in their bids, unreasonably introduces the potential for delay and confusion.

33. The TOD benchmarking methodology exercise here is not for the purpose of adjusting TOD periods; the TOD periods used here are generally consistent with GRC results, TOD periods in tariffs, and other uses of TOD periods; we have already considered and rejected GPI's proposal to time-differentiate the MPR using more than six to nine TOD periods; and GPI did not previously document quantitative benefits of its proposed method that are commensurate with the radically greater granularity of its proposal, and fails to do here.

34. Most, if not all, issues which need to be addressed in R.04-04-026 are resolved and remaining issues, if any, can be efficiently handled, without requiring parties to redo work, by incorporating the record here into a new proceeding.

35. No party requested evidentiary hearing.

Conclusions of Law

1. Electrical corporations should be given flexibility in the way they satisfy RPS program requirements, subject to Commission guidance, limited specific program requirements, and a specific timeframe for the next solicitation cycle.

2. Conditional approval of each Plan and RFO does not constitute endorsement or adoption of each element of each Plan and RFO; rather, IOUs remain responsible for overall program success, subject to flexible compliance and tests of reasonableness.

3. Each proposed RPS procurement Plan and draft RFO filed by PG&E, SCE, and SDG&E should be conditionally approved, subject to the guidance, changes and clarifications stated in this order, including each of the following:

a. allow deliveries anywhere in California

1) each IOU must continue to include its own procurement margin of safety

d. encourage, and in some cases direct, each IOU to:

1) consider whether or not to build their own renewable generation

2) consider reducing bid and other deposits

3) not employ resource stacks in resource selections

4) amend Plans to reflect renewable resource neutrality

5) amend Plans to address CAISO market redesign as ordered herein

6) reconsider disclaimers and elements of IOU discretion

1) require each IOU to report (with its short list of bids and also on submission of advice letters for contract approval) on evaluation criteria and solicitation results, with the report submitted to the PRG and Commission, served on the service list, and available to the public (subject to confidential treatment of protected information)

2) require each IOU to employ an Independent Evaluator to separately report (a preliminary report with the short list, final report with IOU advice letter to approve contracts) on its entire bid, solicitation, evaluation and selection process, with the report submitted to the utility, PRG and Commission; served on the service list; and available to the public (subject to confidential treatment of protected information)

3) encourage each IOU to hold any workshop it believes will advance the program

4) advice parties they may consider using the many ADR tools available at the Commission

5) require each IOU to include an equal treatment, fair dealing and good faith requirement in their RFOs

6) require each IOU to include a clear and consistent statement of evaluation criteria in its Plan, including the benefits of the RPS program identified by the Legislature and in Commission orders

7) provide clarity on environmental stewardship and the relationship to the Commission's Water Action Plan

8) permit multiple simultaneous bids

f. Each individual IOU should amend its plan as explained in this order in areas such as, but not limited to:

1) clarify treatment of transmission (PG&E and SDG&E)

2) include references, where appropriate, to Commission GO 167 (PG&E and SCE)

3) include payment of interest on deposits (SCE)

4) include IPT (SDG&E)

5) strongly encourage a 2006 solicitation (SDG&E)

g. Each Plan is subject to being executed pursuant to the schedule for the next solicitation cycle (see Appendix A)

4. PG&E, SCE and SDG&E should each submit amended Plans and amended RFOs to the Director of the Energy Division within 15 days of the date of this order and, unless suspended by the Energy Division Director within 20 days of the date of this order, each utility shall proceed to use its amended Plan and RFO for its 2006 RPS program and solicitation.

5. The Energy Division Director should modify the adopted schedule and timeframes on the Division's own initiative, as necessary, to bring the next solicitation to reasonable conclusion by the end of 2006 or early 2007, while IOUs and parties should propose schedule modification, if any, by letter to the Executive Director pursuant to Rule 48.

6. Previous orders should be restated so that it is clear to each IOU that it ultimately remains responsible for program success, within application of flexible compliance criteria, and the Commission will later evaluate the extent of that success, including the degree to which each IOU elects to take the guidance provided herein; reasonably demonstrates creativity, innovation and vigor in program execution; and reaches program targets and requirements.

7. In a future defense of a non-compliance penalty, if any, the IOU should be required to show it took all reasonable actions to achieve compliance, and the burden to show why compliance was not met should rest with the utility, including, but not limited to showing that:

a. The IOU brought problems with achieving program goals to our attention without unreasonable delay; proposed reasonable solutions; filed applications for necessary projects (e.g., transmission lines, utility owned generation projects) and other program elements, as necessary, without unreasonable delay; and took all other actions reasonably necessary to address potential problems in reaching RPS program targets.

b. The margin of safety adopted by the IOU was reasonable, a higher margin could not have been reasonably foreseen at reasonable cost to have achieved RPS program goals and requirements, and the IOU reasonably managed its adopted margin of safety.

c. The IOU undertook reasonable consideration of building its own renewable generation facilities, including a consideration of an increased rate of return authorized for eligible utility renewable generation facilities.

d. Bid deposits before creation of the shortlist were required; bid deposits greater than those of PG&E are based on good cause; and in all other respects all bids, deposits and collateral requirements were not unreasonable and did not unreasonably prevent RPS projects from being proposed and developed.

e. Disclaimers and IOU discretion that an IOU retains in each Plan were not unreasonable and did not unreasonably prevent RPS projects from coming forward to be proposed and developed.

f. All workshops an IOU could reasonably foresee as helpful to renewable generator development were conducted by the IOU.

8. IOUs should, at their option, have the ability to treat contracts resulting from the 2006 RPS solicitation, but signed after December 31, 2006, as available to demonstrate compliance with their 2006 APT, in the event of deficits greater than 25%, as long as those contracts are signed on or before 45 days after the Commission adopts the resolution approving PPAs from the 2006 solicitation.

9. PG&E's request to defer the earmarking deadline for the 2005 solicitation from June 30, 2006 to September 30, 2006 should be granted.

10. The Assigned Commissioner or ALJ should set a schedule for the filing and service later this year of 2007 draft RPS plans and draft RFOs; should set a schedule related to TRCRs; and the Assigned Commissioner should determine whether draft TRCRs should be modified, or other steps taken, before the TRCRs are used in the LCBF ranking of bids.

11. The law permits an IOU to procure renewable generation from itself and states it is not to be understood to imply that the purchase of electricity from third parties in a wholesale transaction is the preferred method of fulfilling a retail seller's RPS obligations.

12. The 2006 TOD factors developed by SCE and PG&E should not be used for either utility's 2005 RPS solicitation.

13. This record should be incorporated into a new OIR.

14. Evidentiary hearing is not necessary.

15. This proceeding should be closed.

16. This order should be effective today so that the 2006 RPS solicitation may proceed without delay, the record may be incorporated in the new OIR without delay, and pending matters may be addressed in the new proceeding without delay.

ORDER

IT IS ORDERED that:

1. The following documents, which are the utility proposed renewables portfolio standards (RPS) procurement plans (Plans) and Power Purchase Agreements (PPAs) or Requests for Offers (RFOs), are conditionally approved for the next RPS solicitation cycle:

a. The Pacific Gas and Electric Company (PG&E) "2006 Renewable Energy Procurement Plan" and "Renewables Portfolio Standard Solicitation Protocol" filed December 22, 2005, and the "Supplement to the Draft 2006 Renewables Portfolio Standards Solicitation Protocol of Pacific Gas and Electric Company Filed December 22, 2005 and TOD Factors Benchmarking Study" filed February 8, 2006.

b. The Southern California Edison Company (SCE) "2006 Renewables Portfolio Standard Procurement Plan" filed December 22, 2005 (including the 2006 Request for Offers (RFOs) represented by SCE to be substantially identical to SCE's 2005 RFO), and the SCE "2006 Time-of-Delivery Factors" filed January 10, 2006.

c. The San Diego Gas & Electric Company (SDG&E) "2006 Short-Term Renewable Procurement Plan" filed December 22, 2005.

2. Each document referenced above is adopted on the condition that:

a. Within 15 days of the date of this order, PG&E, SCE and SDG&E shall each file with the Director of the Energy Division, and serve on the service list, an amended Plan and PPA or RFO consistent with all the orders in this decision, plus all guidance in this decision with which the utility agrees, in particular as identified in Conclusion of Law 3.

b. Unless suspended by the Energy Division Director within 20 days of the date of this order, each utility shall use each amended Plan and PPA or RFO for its next solicitation.

3. The 2006 RPS procurement cycle shall be as stated in Appendix A. The schedule may be modified by the Energy Division Director as reasonable and necessary for efficient administration of this solicitation, with the goal of bringing this solicitation to reasonable conclusion no later than early 2007, and parties shall comply with any such modified schedule. Parties may seek schedule modification by letter to the Executive Director (pursuant to Commission Rules of Practice and Procedure), and, if granted, shall be subject to any such modifications.

4. Each utility ultimately remains responsible for reasonable RPS program outcomes, within application of flexible compliance criteria. The Commission shall later review the results of renewable resource solicitations submitted for Commission approval, and accept or reject proposed contracts based on consistency with each approved Plan. The Commission shall also judge the contract results, program results, and non-compliance pleadings by, but is not limited to, considering the degree to which each utility reasonably elects to take or reject the guidance provided herein; reasonably demonstrates creativity, innovation and vigor in program execution; reaches program targets and requirements; shows it took all reasonable actions to achieve compliance, including but not limited to the factors identified in Conclusion of Law 7.

5. PG&E's request to defer the earmarking deadline for the 2005 solicitation from June 30, 2006 to September 30, 2006 is granted for PG&E.

6. Each utility shall, at its option, have the ability to treat contracts resulting from the 2006 RPS solicitation, but signed after December 31, 2006, as available to demonstrate compliance with its 2006 Annul Procurement Target, in the event of deficits greater than 25%, as long as those contracts are signed on or before 45 days after the Commission adopts the resolution approving the PPAs resulting from the 2006 solicitation.

7. The Assigned Commissioner or ALJ in Rulemaking (R.) 04-04-026 (or its successor proceeding with regard to ongoing implementation and administration) shall set a schedule for the filing and service later this year of draft RPS plans and draft RFOs for the 2007 solicitation, and subsequent draft RPS plans and draft RFOs, as necessary. The Assigned Commissioner or ALJ shall set a schedule for matters related to Transmission Ranking Cost Reports (TRCRs) to be used in the ranking of bids in an RPS solicitation. The Assigned Commissioner shall assess the adequacy of each TRCR based on filed comments and reply comments, and shall determine whether each TRCR shall be approved, modified, or other steps taken before a TRCR is used in ranking bids in an RPS solicitation.

8. Each utility shall allow periodic oversight of the work of the Independent Evaluator by the Commission's Energy Division, and shall coordinate to a reasonable degree with assigned Energy Division management and staff as a check on the process. The Independent Evaluator shall also make periodic presentations regarding its findings to the utility and the utility's Procurement Review Group (PRG). This process shall preserve the independence of the Independent Evaluator by ensuring free and unfettered communication between the Independent Evaluator and the Commission's Energy Division, and an open, fair, and transparent process that the PRG can confirm.

9. The record in R.04-04-026 is incorporated into the record in a new Order Instituting Rulemaking (OIR) on the RPS program. The motions for confidential treatment of certain portions of some pleadings in R.04-04-026 shall be part of the record incorporated into the new OIR, and the motions shall be ruled upon there.

10. No hearing is necessary.

11. R.04-04-026 is closed.

This order is effective today.

Dated May 25, 2006, at San Francisco, California.

Commissioner Dian M. Grueneich recused

herself from this agenda item and was not

part of the quorum in its consideration.

APPENDIX A

RPS SOLICITATION TIMELINE

(Updated from D.04-07-029 and D.05-12-042)

· Utilities file annual RPS procurement plans and RFOs.

· CPUC approves procurement plans and RFOs.

· CPUC reviews advice letters submitting contracts.

· Contracts are approved by adoption of Commission resolution.

ADOPTED SCHEDULE

FOR 2006 SOLICITATION

ITEM

NO. OF DAYS

APPROXIMATE DATES

CPUC's Conditional Approval of RPS Plans

0

5/25/06

IOUs file amended RPS Plans

15

6/9

IOUs issue RFOs (unless amended Plans are suspended by Energy Division Director by Day 20)

22

6/16

Respondents file Notice of Intent to Bid

29

6/23

Bidders Conferences

36

6/30

Deadline for Bids

92

8/25

IOUs validate and clarify bids

99

9/1

IOUs notify CPUC Executive Director when Bidding Closed

103

9/5

MPR calculated and Draft Resolution filed

103

9/5

IOUs develop Short Lists

    

CPUC Adopts MPR Resolution

133

10/5

IOUs submit short lists to PRGs and CPUC (with report on evaluation criteria and selections; also Independent Evaluator Preliminary Report)

134

10/6

PRGs review IOU Short Lists

    

IOUs and bidders negotiate and execute PPAs

158

10/30

IOUs submit ALs with PPAs for CPUC Approval (with updated IOU report on evaluations and selections, and Independent Evaluator's Final Report)

166

11/6

Draft Resolution Approving some or all PPAs in ALs

174

11/14

CPUC adopts Resolution on PPAs (last meeting in 2006)

204

12/14

Sellers confirm PCG funding with IOUs within 10 days of receiving SEP notice from CEC

234

1/13/07

IOUs submit amended AL, as necessary, with revised proposed contracts reflecting SEPs

244

1/23

Draft Resolution Approving some or all amended PPAs

251

1/30

Commission adoption of Resolution on Amended PPAs

281

3/1

(END OF APPENDIX A)

APPENDIX B

SUMMARY OF TOD BENCHMARKING METHODOLOGY PROPOSALS AND COMMENTS

A summary of the TOD benchmarking methodology proposals and comments follows.

1. PG&E Proposal

PG&E proposes comparing on-peak TOD factors developed from published on-peak forward power prices to a set of modified IOU-specific RPS TOD factors that have been modified to reflect a comparable on-peak time period. PG&E initially proposed this based on the relative value of forward energy prices. PG&E modified this via a later supplement to incorporate in both its TOD factors and methodology the residual fixed costs of new peaking resources. PG&E says, given PG&E's need to meet Commission-adopted resource adequacy requirements, it is appropriate to account for the additional cost of new peaking capacity, which will be needed as early as 2008. The original and revised TOD factors are as follows:

Monthly Period

Super Peak

Shoulder

Night

 

Orig

Rev

Orig

Rev

Orig

Rev

June-Sept

1.502

1.959

0.992

0.903

0.716

0.626

Oct-Dec; Jan-Feb

1.343

1.471

1.090

1.030

0.810

0.731

March-May

1.114

1.319

0.928

0.843

0.676

0.584

Source: February 8, 2006 Supplement, page 5

Original: December 22, 2005 Solicitation Plan based on energy only

Revised: February 8, 2006 Supplement to Draft 2006 RPS Solicitation Protocol based on energy and new peaking capacity

PG&E says deviations between TOD factors and benchmarks should be expected and should not serve as an indicator of error or unreasonableness. Rather, according to PG&E, deviations might indicate the need for further investigation. PG&E illustrates its energy benchmarking methodology and reports:

Period

Modified On Peak RPS TOD Factor

On Peak TOD Ratios based on Market Forward Information

June-Sept

1.20

1.20

Oct-Dec; Jan-Feb

1.20

1.18

Mar-May

1.00

1.09

PG&E proposes as its capacity benchmarking methodology the calculation of net capacity cost in three steps. First, the annual real economic carrying charge fixed cost of a new combustion turbine can be benchmarked using publicly available sources when actual market bids are not available. Second, expected net energy benefits are calculated using the Black option model as a function of several variables (e.g., NP 15 peak energy forward price; citygate natural gas prices; variable operation and maintenance costs; volatility of NP 15 peak energy forward prices; volatility of citygate gas forward prices; correlation between peak energy forward prices and gas forward prices). PG&E recommends using current market information rather than historic information. Third, the net capacity cost is calculated. PG&E says the allocation of the resulting net capacity cost does not involve proprietary information, and is allocated using the allocation factor formula PG&E currently uses to allocate capacity payments to qualifying facilities.

2. SCE Proposal

SCE's 2006 TOD factors are as follows:

Source: SCE's January 10, 2006 compliance filing pursuant to D.05-12-042, page 2.

SCE proposes close inspection of SCE input data and methodology in lieu of a separate benchmarking process. SCE says it believes a detailed review of the inputs and methodology utilities use to calculate TOD profiles is the appropriate way to evaluate those profiles. According to SCE, this is because TOD factors are forward looking for 10 to 20 years using prospective data, and the benchmarking process must also use prospective data. SCE asserts that, in the near-term, there will never be any proof that the factors selected are correct. To the extent the benchmarking process relies on publicly available historic data, there is a significant probability of a disconnect, according to SCE. Thus, SCE asserts that the process of exercising quality control on the data and methods used to calculate the TOD factors is itself the benchmarking effort.

In its supplement, SCE restates that instead of benchmarking, SCE recommends the Commission exercise quality control over SCE's data and methodology. SCE says the Commission can exercise this quality control by using a validation methodology that reasonably recreates SCE's data and methodology while replacing SCE's proprietary data with publicly-available data. SCE's validation methodology uses four pieces of data: annual SP 15 forward 7x24 electricity prices; SCE's incremental cost of firm capacity, as defined by a combustion turbine proxy; SCE's relative loss of load probability factors by TOD period; and historical hourly SP 15 Power Exchange data. SCE proposes forward electricity price data that can be purchased by the public from brokers. Other data comes from SCE's 2006 General Rate Case or historical data. SCE performs an illustrative calculation, which shows SCE TOD factors differ from validation factors by between zero and 14%. Relying entirely on publicly-available data will not allow precise replication of SCE's filed TOD factors, according to SCE. Nonetheless, SCE says the two sets of factors are reasonably consistent and illustrate that SCE's TOD factors are fair and reasonable.

3. SDG&E Proposal

SDG&E's TOD factors are as follows:

Source: Procurement Plan, December 22, 2005, Appendix A, page 12

SDG&E recommends TOD profiles be benchmarked for reasonableness based on the logic of the calculation, and the reasonableness of the underlying assumptions, using a qualitative evaluation, not a quantitative assessment. SDG&E says its TOD factors are based on the following factors, almost all publicly-available: historical California Power Exchange hourly price data adjusted so the on-peak to off-peak ratios equal those from the 2006 SP-15 forward electric market. The forward prices are available to the public through a fee-based subscription, according to SDG&E.

SDG&E says the logic of its TOD profile is that the hourly PX profile is an adequate hourly profile, but is based on hydro and weather conditions in 1999-2000, which should be updated based on current forward prices. SDG&E adjusts all hourly prices proportionately, but says other methods are available and the Commission must assess whether proportional adjustment is reasonable. Adjustments should also be judged for reasonableness based on external implications, according to SDG&E. For example, SDG&E asserts an adjustment that makes the TOD profile more "peaky" should be consistent with a utility resource plan showing the need for peaking resources.

SDG&E says it will work with its PRG and Energy Division to provide adequate information to ensure success of the benchmarking process, and success will occur if the process does not require extensive utility or Commission resources while satisfying the Commission that the TOD profiles are reasonable. SDG&E says confidential data will be redacted in public versions of the data.

4. DRA Comments

DRA recommends that all utilities use an approach similar to SCE's for benchmarking TOD proposals (largely because DRA finds SCE's TOD proposal best reflects the correlation between TOD and capacity values). DRA also proposes the application of a hypothetical solar plant to benchmark the utility TOD factors.

5. Aglet Comments

Aglet recommends that the Commission adopt the energy benchmarking proposal of PG&E for all IOUs (with some modification), but that IOUs not use capacity benchmarks or combustion turbine proxies in their benchmarking analyses. Further, Aglet recommends use of forward prices from the New York Mercantile Exchange website from the last trading day of the year, not from sources which require paying a fee. Aglet believes that non-market participants should be allowed to participate in investigations of divergent TOD/benchmarking results.

6. GPI Comments

GPI finds that IOUs have produced TOD factors for their 2006 solicitations that are reasonably representative of expected future values profiles, although they could be made better. GPI recommends benchmarking against historic market information, and utility demand curves, as well as quality control measures. GPI believes hourly profiles are superior to a more limited number of TOD periods, and that more periods should be considered, at least in some cases.

7. Solel Comments

Solel believes the PG&E and SCE Supplements represent better approaches to evaluating and calculating TOD profiles, they should accepted, and they should be applied to the 2005 as well as 2006 and future RPS solicitations.

(END OF APPENDIX B)

30 CPUC staff are not allowed to see the results of the RPS solicitations until the Commission adopts the MPR resolution.

31 Utility evaluation process may begin prior to MPR release and adoption.

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