BIDDERS CONFERENCE July 20, 2006

1. RENEWABLES PORTFOLIO STANDARD BIDDERS CONFERENCE July 20, 2006 2006 SOLICITATION

2. Agenda • Introduction • Overview and RFO Schedule • Commercial Overview • Transmission Ranking Costs • Evaluation Methodology • Solicitation Documents • Q & A

3. Overview

4. Differences from 2005 Solicitation • Delivery anywhere in California • Sites for development • Evaluation methodology

5. Eligible Resources • Biodiesel • Biomass • Digester Gas • Fuel Cells using renewable fuels • Geothermal • Landfill Gas • Municipal Solid Waste • Ocean Wave, Ocean Thermal, and Tidal Current • Photovoltaic • Small Hydroelectric (30 MW or less) • Solar Thermal • Wind

6. RFO Goals Target: 700 – 1400 GWh/Year

7. RFO Schedule

8. RPS Regulatory Process PG&E files Contracts for PUC approval No SEPs Contract Execution PG&E files Contracts for PUC approval SEPs Project applies to CEC for SEPs SEP is Supplemental Energy Payment

9. Commercial Overview

10. Power Purchase and Sale Agreement (PPA) Offers • Up to six discrete Offers allowed for a PPA for each Project. Offers may vary by: • Size • Commercial Operation Date • Delivery Term • Generation Profile • Credit Terms • Offers must also include pricing variations with and without Production Tax Credit (if applicable). These variations do not count toward the six allowed Offers.

11. Ownership Offers • Participants may propose a Buyout Option with a PPA Offer • Participants may propose to develop, permit, and construct a facility for purchase by PG&E upon commercial operation • Firm Fuel Cost • O&M Proposal with firm pricing • Participants may propose to sell a site suitable for development of renewable resources by PG&E, including: • Projects in development • Existing facilities with expansion potential

12. PPA Contract Structure Three Individual Power Purchase and Sale Agreements (PPA) • As-Available (eligible to participate in EIRP) • As-Available (not eligible to participate in EIRP) • Baseload, Peaking, or Dispatchable EIRP is Eligible Intermittent Resource Program

13. Non-Modifiable Standard Terms & Conditions

14. Modifiable Standard Terms & Conditions Refer to Appendix A in CPUC Decision 04-06-014, issued June 9, 2004 for guidance on additional Standard Terms and Conditions, which may be modified by either party to the contract. Those terms include the following: • Performance Standards/Requirements • Product Definitions • Non-Performance or Termination Penalties and Default • Credit Terms • Contract Modifications

15. PPA Key Commercial Terms • Contract Price is $/MWh (all-in) for sale of energy and capacity for all products except Dispatchable • Dispatchable - $/kW-year for capacity, $/MWh for energy • Seller is or hires its own Scheduling Coordinator or equivalent – all deliveries SC-to-SC trades or equivalent • Delivery Point is NP-15, SP-15, ZP-26, or anywhere else in California (will also consider out-of-state if deliverable to CA) • Minimum performance criteria apply to all products • Seller receives the Contract Price as adjusted by TOD Factors

16. Time of Delivery (TOD) Factors

17. Baseload, Peaking Products:Minimum Capacity Factors, Performance Adjustments

18. Dispatchable Products: Price, Payment • Capacity Price in $/kW for each year • Energy Price in $/MWh • Capacity Payment subject to Time of Availability (TOA) Factors and Minimum Availability • Performance Adjustments

19. Credit • Bid Deposit of $3/kW upon Shortlisting • Project Development Security of $3/kW from contract execution until CPUC Approval • Following CPUC Approval, Project Development Security of $20/kW • Upon commercial operation, Delivery Term Security of: • 6 months revenue for 10 year contracts • 9 months revenue for 15 year contracts • 12 months revenue for 20 year contracts • Bid Deposit and Project Development Security – cash or Letter of Credit • Delivery Term Security – cash, Letter of Credit, or acceptable guaranty See Table XI.I in Solicitation Protocol

20. Transmission

21. Transmission • Transmission Availability and Cost - Part of RFO Evaluation • Purpose – Provide information for bidders to adjust proposals • => Least Cost Best Fit

22. Consideration of Transmission Cost in Bid Ranking (D.04-06-013 and D. 05-07-040) • Generator Cost responsibility - Include in bid price • Direct Assignment Facilities (Gen-tie) • Identify if desire PG&E to evaluate potential for sharing • Wheeling Charges in non-PTO systems • Cost Responsibility – Customers • Network Upgrades • Transmission Adders at Clusters from: • CAISO Interconnection Process (SIS/FS) • Transmission Ranking Cost Report

23. Malin Oregon Captain Jack California Pacific Gas and Electric Co. (PG&E) Pit 1 Round Mt. Delta Metering Station Caribou Olinda Cottonwood Table Mt. Summit Cortina Bellota Fulton Rio Oso Wilson Vaca-Dixon Tracy Tesla Metcalf Moss Landing Gregg Los Banos Helm Panoche Gates Midway Morro Bay Diablo Canyon Southern California Edison (SCE) Vincent Sylmar Renewable resource cluster PG&E Substations • Associated with Renewable Resource Clusters • Clusters for Bid Evaluation Purposes only • Clusters do not have to be Points of Interconnection

24. Transmission Ranking Cost • For Projects that have not completed the SIS/FS • Solely for bid ranking in this solicitation • Based on Proxy transmission facilities • Successful bidders must complete the ISO Interconnection Process Other Commercial Arrangements to allow PG&E to accept bids anywhere in California (D.06-05-039) will be covered in Bid Evaluation – not part of Transmission Section

25. Transmission Ranking Cost Table X.1 • Table X.1 – Transmission Ranking Cost • North of PG&E Service Area – Round Mt. • South of PG&E Service Area – Midway • East of PG&E Service Area - Summit

26. Ways to avoid triggering Next Level of Transmission Ranking Cost Attachment D to the Protocol • “Participant Proposal – Energy Pricing Sheet” • optional “Dispatch Down Provision.” => specify the MW of curtailable capacity • “Generation Profile” that does not trigger transmission upgrades • forecast of average-day net output energy production, in MW by hour, by month and by year. Other Commercial Arrangements will be covered in Bid Evaluation -- not part of Transmission Ranking Cost

27. Table X.1 * Cost of Proxy Voltage Support Devices are to be prorated in proportion to the size of the project.

28. Example • Two bids received: • A: 250 MW (base load) • B: 250 MW (base load) • Bid A has lower cost (or higher value) Transmission Adder to be used in Evaluation “In ranking RPS bids, PG&E, SCE, and SDG&E shall each allocate costs of transmission upgrades that would be used by more than one RPS project on a pro rata basis, based on the percentage of transfer capacity added by the proposed upgrade that would be used by the RPS project: This pro rata allocation of upgrade costs shall be applied only if sufficient renewables potential exists, as identified by the California Energy Commission, to fully utilize the transmission facility sometime in the future."

29. Example • Bid B can specify curtailable MW • B: 250 MW • Night Curtailable: 150 MW Transmission Adder to be used in Evaluation

30. Example • Bid B can adjust its Generation Profile: • Peak and Shoulder: 250 MW • Night: 100 MW Transmission Adder to be used in Evaluation

31. Evaluation Methodology

32. Evaluation Criteria • Market Valuation • Portfolio Fit • Transmission Adders/Integration Costs • Credit • Status of Project • Technology Viability • Consistency with RPS Goals • Modifications to Form Agreements

33. Quantitative Evaluation • Market Valuation: Price Based • Value of contract is the net of energy benefit and the total cost. • Portfolio Fit: Open Position Based • Comparison of the contract online date and generation profile to PG&E’s existing hourly, seasonal and annual needs.

34. Market Valuation: Benefit • Baseload, Peaking Contracts • Contract benefit is evaluated based on (deterministic) market forwards prices. • As-Available Contracts • Contract benefit is evaluated based on (deterministic) market forwards prices but with variable quantity. • Dispatchable Contracts • Contract is evaluated as call option on energy. Benefit is expected value of energy.

35. Market Valuation: Cost • Baseload, Peaking, As-Available • Cost is calculated as energy generation times offer price times TOD factors for each period. • Dispatchable • Cost is the energy generation times the expected offer price, plus a capacity charge distributed monthly by a TOA factor. TOD is Time of Delivery; TOA is Time of Availability

36. Portfolio Fit • Complementary to price based valuation. • Contract portfolio fit statistic is the change in the fit metric with and without the new contract. • Variability of open positions • Price independent • Shape and timing of energy matter

37. Transmission Adders • Transmission Ranking Cost Report • Alternative Commercial Arrangements • Remarketing • Swaps • As-available transmission • Use lesser of the two

38. Credit • Participant’s financial strength • Credit concentration • Performance Assurance • Project Development Security • Delivery Term Security

39. Status of Project • Permits • Equipment • Site Control • Transmission Studies • Financing • Design/Construction

40. Technology Viability • Resource Risk • Historical Commercial Data • Participant Experience

41. Consistency with RPS Goals • CPUC-stated Goals • Legislative Findings • Impact on Water Quality • Supplier Diversity

42. Modifications to Forms • Materiality • Cost Impact

43. Evaluation Methodology • Quantitative Evaluation • Market valuation, portfolio fit, transmission • Scoring for other categories • Credit, Status, Technology, RPS Goals • Each offer is compared to other offers in the quantitative and other scoring categories

44. Evaluation Methodology • Offer A will be ranked higher than Offer B if Offer A has a score at least as high as Offer B on each of the criteria and if Offer A has a score higher than Offer B on at least one criteria • Offers that are strong relative to others will be in top group • Offers that are weak relative to others will be in bottom group • Offers that are strong in some but weak in other criteria relative to others will require judgment • Shortlist will err on side of greater inclusion

45. Solicitation Documents

46. Solicitation Process • Offers must be received by PG&E by Friday, September 8, 2006 at 3:00 p.m. (PPT) • Both Electronic and Hard Copies • Hard copies (4 Bound & 1 Unbound) delivered to: RPS Solicitation Electric Supply Department Pacific Gas & Electric Company 245 Market Street, Room 1285A, Mail Code N12G San Francisco, CA 94105 • Electronic copies - two (2) compact discs (CDs) accompanying the hard copy of the documents.

47. Bidding Forms • Signed RPS Solicitation Protocol Agreement (Attachment A) • Fully Completed Offer Form (Attachment D) • Participant Credit-Related Information Form (Attachment E) • FERC Order 2004 Waiver (Attachment F) All forms described in Section VIII.C. of the Solicitation Protocol

48. Bidding Forms (cont’d) • Applicable Form of PPA (Attachments G, H, and/or I), including proposed modifications. • Buyout Offers must also include a fully completed term sheet (Attachment J) in addition to PPA. • Ownership Offers must include a fully completed term sheet (Attachment K) instead of a PPA. All forms described in Section VIII.C. of the Solicitation Protocol

49. Bidding Forms (cont’d) • Participant attachment • Project Description • Site Control • Milestone Schedule • Transmission/Interconnection • CEC, SEP, SB90 funding • Experience and Qualifications • Support of RPS goals and water quality All forms described in Section VIII.C. of the Solicitation Protocol

50. CEC Requirements • RPS Eligible Renewable Energy Resources (ERR) must be CEC Certified • CEC Certification/Pre-Certification should be applied for now, and should be obtained prior to contract execution • Supplemental Energy Payments (SEPs) are awarded by the CEC • Apply to CEC for SEPs when PPAs are executed • ERRs must report their renewable generation to a CEC Generation Tracking System