BIDDERS CONFERENCE APRIL 3, SOLICITATION RENEWABLES PORTFOLIO STANDARD

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

2 Commercial Overview

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

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

5 RFO Schedule DATEEVENT April 3, 2007Bidders Conference TBD in May, 2007Bidder workshop – forms, Q&A May 31, 2007, 10 a.m.Deadline to submit Offer(s) June 29, 2007Shortlist notification July 10, 2007Offer deposits due from shortlisted bidders July 16, 2007PG&E submits Shortlist to PRG and CPUC TBDCPUC issues Market Price Referent (“MPR”) By December 31, 2007 Negotiate and execute Agreements; PG&E submits Agreements for Regulatory Approval See Section II of the Solicitation Protocol

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

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 See Section VIII of the Solicitation Protocol

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

9 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

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) See Attachments G and H of the Solicitation Protocol

11 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 Monthly PeriodSuper-PeakShoulderNight Jun – Sep Oct.- Dec., Jan. & Feb Mar.– May See Section IX of the Solicitation Protocol

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 Month TOA Factor Minimum Availability January4.7%90% February2.9%90% March2.3%70% April3.2%70% May4.2%70% June7.1%95% July15.7%95% August17.8%95% September16.9%95% October10.3%90% November7.6%90% December7.3%90% See Section IX of the Solicitation Protocol

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 Term10 years15 years20 years Months Revenue6912 See Sections V and VII of the Solicitation Protocol

14 Shortlisting Evaluation Methodology

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 See Section XI and Attachment K of the Solicitation Protocol

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.

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.

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

19 Credit  Performance Assurance  Project Development Security  Delivery Term Security

20 Project Viability  Project Status  Permits  Site Control  Equipment  Technology Viability and Participant Experience  Resource Risk  Historical Commercial Data  Participant Experience  Transmission Studies  Financing  Design/Construction

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)

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

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

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

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

26 Transmission Ranking Costs

27  Pursuant to D and D  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 Consideration of Transmission Cost in Bid Ranking See Section X of the Solicitation Protocol

28 Cost Allocation of Transmission Facilities needed for Renewables 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 : 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 : Back- stop only – Roll into Retail Rates of the 3 CA IOUs

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

30 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

31 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

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

33 Table X.1 * Cost of Proxy Voltage Support Devices are to be prorated in proportion to the size of the project. Substation Associated With Cluster Of Potential Generation Level Peak and ShoulderNightBase Load and As Available Year Round Maximum MW of Potential Generation In each Level Cost of Proxy Network Upgrades to accommodate MW Level of Potential Generation ($ millions in 2007 dollars) Maximum MW of Potential Generation In each Level Cost of Proxy Network Upgrades to accommodate MW Level of Potential Generation ($ millions in 2007 dollars) Maximum MW of Potential Generation In each Level Cost of Proxy Network Upgrades to accommodate MW Level of Potential Generation ($ millions in 2007 dollars) Proxy Voltage Support Devices* Other Proxy Transmission upgrades Proxy Voltage Support Devices* Other Proxy Transmission upgrades Proxy Voltage Support Devices* Other Proxy Transmission upgrades Fulton 230 kV

34 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." OfferLevelGen Capacity (MW) Proxy VAR Support ($Million/MW) Other Proxy Network Upgrades ($Million) A A B B

35 Example: Specify Curtailable for Night Period Offer A: Peak & Shoulder: 250 MW Night Curtailable: 50 MW Transmission Adder to be used in Evaluation BidLevel Peak and ShoulderNight Gen Capacity (MW) Proxy VAR Support ($Million/ MW) Other Proxy Network Upgrades ($Million) Gen Capacity (MW) Proxy VAR Support ($Million/ MW) Other Proxy Network Upgrades ($Million) A B Offer B: Peak & Shoulder: 250 MW Night Curtailable: 0 MW Curtailable = curtailed as needed

36 Example: Adjust Gen Profile Offer A Generation Profile: Peak and Shoulder: 250 MW Night: 50 MW Transmission Adder to be used in Evaluation BidLevel Peak and ShoulderNight Gen Capacity (MW) Proxy VAR Support ($Million/ MW) Other Proxy Network Upgrades ($Million) Gen Capacity (MW) Proxy VAR Support ($Million/ MW) Other Proxy Network Upgrades ($Million) A B Offer B Generation Profile: Peak and Shoulder: 250 MW Night: 0 MW

37 Interconnection Process

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,  Distribution Interconnections  Follow Attachment E of WDT e_generators/

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

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

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)

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

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

44 Solicitation Documents

45 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, 13 th floor San Francisco, CA 94105

46 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

47 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

48 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

49 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: See Section IV of the Solicitation Protocol

50 Communications, Website Interaction  All RFO documents are available on PG&E’s website at: and click on 2007 Renewable RFO, or paste and bookmark the following in your browser: electric_supplier_solicitation/renewables2007.html  All announcements, updates and Q&As will also be posted on the website  PG&E prefers that communications be in the form of an to: See Section I of the Solicitation Protocol

51 Q & A