BIDDERS CONFERENCE APRIL 3, 2007

1. BIDDERS CONFERENCE APRIL 3, 2007

2. 1 Agenda Introduction Commercial Overview Shortlisting Evaluation Methodology Transmission Ranking Costs Interconnection Process Solicitation Documents Q & A

3. 2 Commercial Overview

4. 3 New for 2007 Reduced collateral during development Shorter exclusivity period Updated TOD factors Expanded eligibility of out-of-state deliveries Limited RPS-counting of hybrid facilities

5. 4 Highlights Eligible resources Target volumes Products Delivery profiles Delivery term Project location & delivery point Independent Evaluator

6. 5 RFO Schedule

7. 6 RPS Regulatory Process

8. 7 Power Purchase and Sale Agreement (PPA) Offer Variations Up to six discrete Offers for a PPA for each Project. Offers may vary by: Size Commercial Operation Date Delivery Term Generation Profile Credit Terms Pricing variations With and without PTC/ITC If not already in price, premium for delivery to CAISO

9. 8 Ownership Offers PPA with Buyout Option Turnkey Ownership - 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 Site Offers For development or expansion by PG&E

10. 9 PPA Contracts Two Forms of PPA As-Available (Whether or not eligible to participate in EIRP) Baseload, Peaking, or Dispatchable

11. 10 PPA Key Commercial Terms Contract Price is $/MWh (all-in) for all products except: Dispatchable - $/kW-year for capacity, $/MWh for energy Seller is or hires its own Scheduling Coordinator or equivalent Delivery Point is NP15, SP15, ZP26, anywhere else in California, or out-of-state Minimum performance criteria apply to all products Seller receives Contract Price as adjusted by TOD Factors New limited Dispatch Down provision Certain non-modifiable terms (highlighted in online PPAs)

12. 11 Time of Delivery (TOD) Factors

13. 12 Time of Availability (TOA) Factors 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

14. 13 Credit Offer 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 * capacity factor (minimum of $10/kW) Upon commercial operation, Delivery Term Security: Offer Deposit and Project Development Security � cash or Letter of Credit Delivery Term Security � cash, Letter of Credit, or acceptable guaranty

15. 14 ShortlistingEvaluation Methodology

16. 15 Evaluation Criteria Ranking based on combination of Quantitative and Qualitative factors Quantitative Evaluation Market Valuation Transmission Adders Qualitative Evaluation Portfolio Fit Credit Project Viability Consistency with RPS Goals Modifications to Form Agreements

17. 16 Market Valuation Market-Based Valuation Value of contract is capacity plus the net of the energy benefit and cost. The energy benefit is computed using market prices, volatilities, and correlations. Capacity value is based on: the net economic carrying cost of a new combustion turbine contribution to PG&E�s Resource Adequacy requirements. As-Available Contracts Contract benefit is evaluated based on (deterministic) market forward prices, but with variable quantity, and the value of capacity. Cost is calculated as energy generation times offer price times TOD factors for each period.

18. 17 Market Valuation (continued) Baseload, Peaking Contracts Contract benefit is evaluated based on (deterministic) market forward prices and the value of capacity. Cost is calculated as energy generation times offer price times TOD factors for each period. Dispatchable Contracts Contract is evaluated as call option on energy. Benefit is the value of capacity and the expected value of energy. Cost is the energy generation times the expected offer price, plus a capacity charge distributed monthly by a Time of Availability factor.

19. 18 Portfolio Fit Differentiates offers by the firmness of their energy delivery and by their energy delivery patterns Firmness (predictability) is preferred Delivery when PG&E is short is preferred Dispatchability is preferred

20. 19 Credit Performance Assurance Project Development Security Delivery Term Security

21. 20 Project Viability Project Status Permits Site Control Equipment Technology Viability and Participant Experience Resource Risk Historical Commercial Data Participant Experience

22. 21 Consistency with RPS Goals CPUC-stated Goals Legislative Findings Governor�s Order on biomass Impact on Water Quality PG&E�s Supplier Diversity (WMDVBe)

23. 22 First Ranking Shortlist rankings are relative No fixed cut-off price No fixed procurement limit Based on quantitative and qualitative factors 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 Then, introduce transmission adders

24. 23 Transmission Adder - �the lower of� Use �the lower of� the result of the Transmission Ranking Cost Report or Alternative Commercial Arrangements (remarketing, swaps, or as-available transmission) For projects north of PG&E�s service area, comparison is between TRCR result at Round Mountain and price basis between COB and NP15 For projects south of PG&E�s service area, comparison is between TRCR result at Midway and price basis between SP15 and NP15 When no Alternative Commercial Arrangement is feasible, and no transmission study results are available, use the TRCR Example Offer for baseload energy at PG&E�s Panoche cluster, needing upgrades No opportunity for remarketing Project must incur upgrade costs to effect delivery

25. 24 Second Ranking Market Valuation is adjusted for Transmission Adders, resulting in a Net Value Offers are re-ranked, just like first ranking, but using the new Net Value instead of Market Value Offers strong relative to others will be in top group Offers weak relative to others will be in bottom group Offers strong in some but weak in other criteria relative to others will require judgment Shortlist will err on side of greater inclusion

26. 25 Consultation with PRG and IE Discuss proposed shortlist and evaluation methodology Solicit feedback on whether certain offers should be included and whether certain offers should be excluded Incorporate feedback and finalize shortlist

27. 26 Transmission Ranking Costs

28. 27 Consideration of Transmission Cost in Bid Ranking

29. 28 Cost Allocation of Transmission Facilities needed for Renewables

30. 29 PG&E Substations Associated with Renewable Resource Clusters

31. 30 Transmission Ranking Cost

32. 31 Transmission Ranking Cost Table X.1

33. 32 Ways to avoid triggering Next Level of Transmission Ranking Cost Attachment D to the Protocol Energy Pricing Sheet Optional �Dispatch Down Provision� * Specify the MW of curtailable capacity Gen Profile Sheet 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

34. 33 Table X.1

35. 34 Example

36. 35 Example: Specify Curtailable for Night Period

37. 36 Example: Adjust Gen Profile

38. 37 Interconnection Process

39. 38 Generation Interconnection Study Process Transmission Interconnections All Applications must be submitted with the CAISO Generators less than or equal to 20 MW, follow Amendment 39 Generators greater than 20 MW, follow Large Generator Interconnection Procedures (LGIP) Information on Amendment 39 Process and LGIP found on CAISO Website, http://www.caiso.com/docs/2002/06/11/2002061110300427214.html Distribution Interconnections Follow Attachment E of WDT http://www.pge.com/suppliers_purchasing/new_generator/wholesale_generators/

40. 39 Amendment 39 Process Interconnection Application (IA) $10,000 refundable deposit to CAISO Deposit is not applied to study costs System Impact Study (SIS) Deposit is based upon estimated study costs � typically around $20,000 to initiate SIS process (Applicant pays actual cost at end of study) Study Period � 60 CD or more Facilities Study (FS) Deposit is based upon estimated study costs - typically $40,000 for study cost (Applicant pays actual cost at end of study) Study Period - 60 CD or more Total Study Time � 6 to 9 months

41. 40 Amendment 39 Process (continued) Customer must request an Interconnection Agreement within 10 BD of receiving the final FS Interconnection Agreement is tendered within 30 BD of request. IA must be filed and accepted at FERC Process may change because CAISO & PG&E have filed with FERC to adopt the Small Generator Interconnection Procedure (SGIP) � waiting on FERC to accept filing

42. 41 Large Generator Interconnection Procedures (LGIP) Interconnection Request (IR) $10,000 deposit and proof of site control Additional $10,000 without proof of site control Deposits are applied to the study costs Interconnection Feasibility Study (IFS) Additional $10,000 deposit to initiate IFS process (Applicant pays actual cost at end of study) Study Period � 60 CD Interconnection System Impact Study (ISIS) $50,000 deposit to initiate ISIS process (Applicant pays actual cost at end of study) Study Period � 120 CD Interconnection Facilities Study (IFAS) $100,000 deposit for study cost (Applicant pays actual cost at end of study)

43. 42 Large Generator Interconnection Procedures (LGIP) Interconnection Agreement (LGIA) Within 30 CD after Draft IFAS comments are received, tender Draft LGIA to Applicant 30 CD Days for Applicant to comment on Draft LGIA 60 CD to negotiation process to address comments 90 CD to execute LGIA following Final IFAS Report Evidence of continued reasonable Site Control or posting to PG&E of $250,000, non refundable security

44. 43 Large Generator Interconnection Procedures (LGIP)

45. 44 Solicitation Documents

46. 45 Offer Submittal

47. 46 Offer Forms due May 31

48. 47 Offer Forms due May 31

49. 48 Additional forms if Shortlisted

50. 49 CEC Requirements

51. 50 Communications, Website Interaction

52. 51 Q & A