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BIDDERS CONFERENCE APRIL 3, 2007

RENEWABLES PORTFOLIO STANDARD. BIDDERS CONFERENCE APRIL 3, 2007. 2007 SOLICITATION. Agenda. Introduction Commercial Overview Shortlisting Evaluation Methodology Transmission Ranking Costs Interconnection Process Solicitation Documents Q & A. Commercial Overview. New for 2007.

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BIDDERS CONFERENCE APRIL 3, 2007

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  1. RENEWABLES PORTFOLIO STANDARD BIDDERS CONFERENCE APRIL 3, 2007 2007 SOLICITATION

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

  3. Commercial Overview

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

  6. RFO Schedule See Section II of the Solicitation Protocol

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

  8. 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 See Section VIII of the Solicitation Protocol

  9. 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 See Section III and Attachments I and J of the Solicitation Protocol

  10. PPA Contracts • Two Forms of PPA • As-Available (Whether or not eligible to participate in EIRP) • Baseload, Peaking, or Dispatchable EIRP is Eligible Intermittent Resource Program

  11. 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) See Attachments G and H of the Solicitation Protocol

  12. Monthly Period Super-Peak Shoulder Night Jun – Sep 2.037 0.921 0.700 Oct.- Dec., Jan. & Feb. 1.203 1.049 0.841 Mar . – May 1.030 0.855 0.656 Time of Delivery (TOD) Factors • As-Available • Payment = Contract Price * TOD Factor * MWh • Baseload, Peaking • Payment = Contract Price * TOD Factor * MWh • Reductions for not meeting minimum performance See Section IX of the Solicitation Protocol

  13. 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 See Section IX of the Solicitation Protocol

  14. 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 See Sections V and VII of the Solicitation Protocol

  15. ShortlistingEvaluation Methodology

  16. 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 See Section XI and Attachment K of the Solicitation Protocol

  17. 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. 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. 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. Credit • Performance Assurance • Project Development Security • Delivery Term Security

  21. Project Viability • Transmission Studies • Financing • Design/Construction • Project Status • Permits • Site Control • Equipment • Technology Viability and Participant Experience • Resource Risk • Historical Commercial Data • Participant Experience

  22. 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. 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. 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. 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. 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. Transmission Ranking Costs

  28. Consideration of Transmission Cost in Bid Ranking • Pursuant to 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 to Delivery Point • Customer Cost Responsibility • Network Upgrades • Transmission Adders at Clusters from: • CAISO Interconnection Process (SIS/FS) • Transmission Ranking Cost Report See Section X of the Solicitation Protocol

  29. Cost Allocation of Transmission Facilities needed for Renewables Network Load Load Load • High Voltage Multi-user Gen-tie: • Existing Tariff: Gen fund. Roll into purchase price • CAISO Proposal: Roll into TAC, Gen reimburses TAC pro-rata. • CPUC I.05-09-005: Back-stop only – Roll into Retail Rates of the 3 CA IOUs, Gen reimburses Retail customers pro-rata. • Network Facilities: • Existing Tariff: Gen fund. Roll into TAC. • CPUC I.05-09-005: Back-stop only – Roll into Retail Rates of the 3 CA IOUs

  30. Malin Captain Jack Oregon 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 Stagg Tesla Metcalf Gregg Los Banos Helm Gates Panoche Midway Morro Bay Diablo Canyon Renewable resource cluster Southern California Edison (SCE) Vincent Sylmar PG&E Substations Associated with Renewable Resource Clusters • Clusters for Bid Evaluation Purposes only • Clusters do not have to be Points of Interconnection

  31. 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 Alternative Commercial Arrangements covered in Shortlist Evaluation Methodology – not part of Transmission Section

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

  33. 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 * This provision is optional and is supplemental to the standard Dispatch Down provision.

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

  35. Example • Two Offers received: • A: 250 MW (base load) • B: 250 MW (base load) • Offer A ranks higher than Offer B Transmission Ranking Cost 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."

  36. Example: Specify Curtailable for Night Period • Offer A: • Peak & Shoulder: 250 MW • Night Curtailable: 50 MW • Offer B: • Peak & Shoulder: 250 MW • Night Curtailable: 0 MW Transmission Adder to be used in Evaluation Curtailable = curtailed as needed

  37. Example: Adjust Gen Profile • Offer B Generation Profile: • Peak and Shoulder: 250 MW • Night: 0 MW • Offer A Generation Profile: • Peak and Shoulder: 250 MW • Night: 50 MW Transmission Adder to be used in Evaluation

  38. Interconnection Process

  39. 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. 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. 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. 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. 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. Large Generator Interconnection Procedures (LGIP) Interconnection Agreement (LGIA) Interconnection Facilities Study (IFAS) Negotiation (60 CD) Study Process (120 CD) Interconnection System Impact Study (ISIS) Study Process (120 CD) Interconnection Feasibility Study (IFS) Study Process (60 CD) Interconnection Request (IR)

  45. Solicitation Documents

  46. Offer Submittal • Offers must be received by PG&E by Thursday, May 31, 2007 at 10:00 am (PPT) • Both Electronic and Hard Copies • Electronic copies - two (2) compact discs (CDs) • Hard copies (5 Bound & 1 Unbound) delivered to: RPS Solicitation Electric Supply Department Pacific Gas & Electric Company 245 Market Street, 13th floor San Francisco, CA 94105

  47. Offer Forms due May 31 • Signed RPS Solicitation Protocol Agreement (Attachment A) • Fully Completed Offer Form (Attachment D) • FERC Order 2004 Waiver (Attachment F) • Applicable Form of PPA (Attachments G or H), including proposed modifications • Buyout Offers must also include a fully completed term sheet (Attachment I) in addition to PPA • Ownership Offers must include a fully completed term sheet (Attachment J) instead of a PPA See Section VIII.C. of the Solicitation Protocol

  48. Offer Forms due May 31 • Attachment • Project Description • Site Control • Milestone Schedule • Transmission/Interconnection • CEC, SEP, SB90 funding • Experience and Qualifications • Support of RPS Goals See Section VIII.C. of the Solicitation Protocol

  49. Additional forms if Shortlisted • Within 5 business days, • Offer Deposit • Confidentiality Agreement (Exhibit 1 to Attachment A) • Credit and Finance Information Form (Attachment E) See Section XIV of the Solicitation Protocol

  50. CEC Requirements • RPS Eligible Renewable Energy Resources (ERR) must be CEC Certified • CEC Certification/Pre-Certification should be obtained prior to contract execution • Supplemental Energy Payments (SEPs) are awarded by the CEC • If needed, apply to CEC for SEPs when PPAs are executed • ERRs must report their renewable generation to a CEC Generation Tracking System • See updated guidebooks at: http://www.energy.ca.gov/renewables/documents/ See Section IV of the Solicitation Protocol

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