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Long-Term Power Procurement Request for Offers Bidders Conference April 21, 2008

Long-Term Power Procurement Request for Offers Bidders Conference April 21, 2008 . Agenda. Introduction Commercial Overview Evaluation of Offers Gas Interconnection Electric Transmission & Interconnection Power Purchase Agreement Purchase & Sale Agreement (Ownership)

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Long-Term Power Procurement Request for Offers Bidders Conference April 21, 2008

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  1. Long-Term Power Procurement Request for OffersBidders ConferenceApril 21, 2008

  2. Agenda • Introduction • Commercial Overview • Evaluation of Offers • Gas Interconnection • Electric Transmission & Interconnection • Power Purchase Agreement • Purchase & Sale Agreement (Ownership) • Credit Requirements • Solicitation Documents • Q&A

  3. Commercial OverviewParticipant ConferenceApril 21, 2008

  4. Commercial Overview • All Source Long-term Request for Offers • New Renewable Generation • New Distributed Generation • Existing or New Qualifying Facilities (“QFs”) • Repowering an existing Facility • New Conventional Generation • 800 – 1,200 MWs • Preference for dispatchable and operationally flexible resources • On-line dates no later than May 2015 • Preference for earlier • Delivery Point: NP15 or if QF to ZP26 • Minimum size of 25 MWs except QF minimum size of 20 MWs • 10 MW site minimum for DG to be aggregated to >25 MW

  5. Commercial Overview • Power Purchase Agreement (“PPA”) • Contract term cannot exceed 10 years • Purchase and Sale Agreement (“PSA”) • Fully permitted and constructed resource sold at commercial operation • Bidders may bid both PPA and PSA • Independent Evaluator for all bids

  6. GHG Performance Standard SB1368 (and the CPUC) sets the GHG Emissions Performance Standard (EPS) for baseload (at least 60% CF) resources New contracts (5+ years) must have a net CO2 emissions rate no higher than 1,100 lbs/MWh CO2 emissions limit applies to each individual generating unit supplying power under contract Existing CCGT baseload powerplants (or those holding a CEC final permit as of 7/30/07) are pre-approved as EPS compliant** Renewable technologies (solar thermal, wind, geothermal, and biomass) are pre-approved as EPS compliant Appendix J – Question 6(c) should refer to SB1368 ** Any deemed-compliant CCGT plant that has added units resulting in an increase of 50+ MW to the plants capacity must again prove eligibility.

  7. April 1 April 21 April 25 April 28 May 9 End May/Early June July 21 – 1:00pm October 20 October 27 PG&E Issues RFO Bidder’s Conference Notice of Intent due Deadline to submit Gas Interconnection Distribution of Form Agreements Bidders Workshop Offers Due Short List Notification Deadline to submit Interconnection to CAISO 2008 Schedule

  8. Evaluation of OffersBidders ConferenceApril 21, 2008

  9. Evaluation of OffersEvaluation Criteria • Quantitative Criterion • Market Valuation • Qualitative Criteria • Portfolio Fit • Credit • Participant Qualifications • Project Viability • Technical Reliability • Environmental Leadership • Conformance with PG&E’s non-price terms and conditions

  10. Evaluation of OffersMarket Valuation • Focus is not an Offer’s cost, but cost compared to benefits • Market value = benefits – costs • Benefits include energy, capacity, and ancillary services • Real option model is used to value dispatchability • Transmission impact and costs to be included • Cost of green house gas (GHG) emissions included • Market valuation is independent of other PG&E positions

  11. Evaluation of OffersPortfolio Fit • Portfolio Fit is dependent on other PG&E positions • Compare an Offer’s features to PG&E portfolio needs • Several criteria considered: • Flexibility of energy delivered • Firmness of energy delivered • Geographical diversity of source • Qualification for local resource adequacy of capacity

  12. Evaluation of OffersCredit • Participant’s capability to perform all of its financial and other obligations • To be discussed in more detail later today

  13. Evaluation of OffersParticipant Qualifications • Experience in developing (licensing & permitting) similar type power plants of: • Developer • EPC contractor • Prime subcontractor • O&M Operator (for PPA) • Particular experience in California

  14. Evaluation of OffersProject Viability • Probability that the project can be financed and completed per Agreement • Considers: • Construction • Project Financing • Permitting

  15. Evaluation of OffersTechnical Reliability • Type of Technology and Equipment • Will the Offer be available to provide capacity, energy, and/or ancillary services when called upon? • Tried & proven with historical evidence of high availability • R&D or pilot project

  16. Evaluation of OffersSupport for PG&E’sEnvironmental Leadership • PG&E seeks opportunities to exceed current standards of environmental protection • Quantity and potential cost to PG&E and to society associated with Offer’s environmental characteristics • Cumulative pollution exposure to a community • Participant’s local community outreach plans

  17. Evaluation of OffersConformance with PG&E Non-price Terms and Conditions • Prefer no markups • Extent of comments • Imputed additional costs or risks

  18. Gas InterconnectionBidders ConferenceApril 21, 2008

  19. Gas Interconnection Discussion • Typical gas connection process • Revised process for LTRFO • Discussion of revised application process

  20. Gas Transmission Interconnection Process Standard gas connection process has 4 steps: 1) Preliminary Request for Information Review (PRIR) (7 days) 2) Preliminary Application for Gas Service (PAGS) (10 weeks) 3) Formal Application for Gas Service 4) Contracts, Construction, and Release to Service To expedite response we will modify the gas connection process

  21. Gas Transmission Interconnection Process Revised process: • Eliminate the PRIR • “Expedite” Preliminary Application for Gas Service • Complete Preliminary Application (once short-listed) • Formal Application for Gas Service (once selected) • Contracts, Construction, and Release to Service June 27 target response for complete applications submitted by April 28

  22. Expedited PAGS • System Impact Study • System capabilities • Size gas service pipeline • Expected pressure • Preliminary Facilities Study • Tap location • Service pipeline alternatives & routes • Standard or Special Facilities Designs • Estimated costs

  23. Overview of Sequence • April 1 Receive bid package • April 28 Deadline for Gas Application to be deemed complete • June 27 Target PG&E response date • July 21 Offers due

  24. Bid Package – Appendix M Application for Gas Transmission Service Agreement to Perform Tariff Scheduled Related Work Instructions

  25. Application for Gas Service Study to PG&E by April 28 Application deemed complete and in queue: • Cover letter • Completed Application for Gas Transmission Service • Meter site location map • Gas usage (annual and monthly) • $15,000 cash advance • 2 signed copies of Agreement to Perform Tariff Scheduled Related Work

  26. Application for Gas Service Study to PG&E by April 28 Cover Letter should request • PG&E to by-pass PAIR • Perform an Expedited PAGS • Response by June 27 • Can request SIS when complete • Release for CT&D to share info with LTRFO Team Engineering priority established upon receipt date of complete application packed Requests after April 28 are at risk

  27. Include in Offer – July 21 • Copy of all documents submitted for gas study • Application for Gas Transmission Service • Cover letter requesting gas service study • Agreement to Perform Tariff Scheduled Related Work • PG&E’s Expedited PAGS response • Gas service configuration requested • Transportation tariff for service

  28. Gas Interconnection PAGS Submittal Application is available electronically http://www.pge.com/b2b/newgenerator/gasinterconnections/ To discuss details of the process, contact Michael O’Brien (415) 973-5652 mdo1@pge.com

  29. Electric Transmission and Interconnection Bidders ConferenceApril 21, 2008

  30. Electric Transmission and Interconnection • Interconnection process must be complete in order for generator to deliver power to the grid and meet obligations of LT RFO contract • Generator responsible for all generation interconnection costs • Generator responsible for timely applications with CAISO and timely completion of the process • Not part of the LT RFO Solicitation • Process should be started early

  31. Electric Transmission and Interconnection Assessing Transmission Impacts • ALL Facilities MUST meet requirements of: • North American Electric Reliability Council (NERC) • Western Electricity Coordinating Council (WECC) • PG&E Interconnection Handbook (PIH) • Have sufficient transmission at the Point of Interconnection to interconnect the generation project and to achieve full project deliverability • Insufficient Transmission Capacity results in need for Network Upgrades

  32. Electric Transmission and Interconnection Funding of Electric Transmission Facilities • Interconnection Facilities (Direct Assignment Facilities) • Participant advances funds to PG&E for any Interconnection facilities to be constructed by PG&E • Advance includes ITCC (Income Tax Contribution Component) • Federal and State • Network Upgrades • Participant advances funds to PG&E for Network Upgrades • ITCC is not included in advance for Network Upgrades • After generating facility is operative, cost advance is refunded to Participant in accordance with GSFA • Quarterly payments with interest (as established by FERC) over 5-year period

  33. CAISO Interconnection Queue • Large Generation Interconnection Process • High Level Transmission Assessment >>> Feasibility Study (FES) • Specific Network Upgrades >>> System Impact Study (SIS) • Specific Network Upgrade Costs >>> Facility Study (FS) • Reformed Process • Queue Clusters >>> Single Study to Determine Network Upgrade Cost Allocation • Transmission Planning Process >>> Determine Specific Transmission Upgrades to Address New Generation and Grid Reliability Needs

  34. CAISO Generation Interconnection Process Reform • CAISO Interconnection Process is currently being reformed to address a backlog in the interconnection queue • Current queue will be closed at the end of May. New queue will open on June 2 and will not close until November 28 at the earliest. • Projects applying for interconnection before the current cluster closes will be studied this year as part of a queue clearing study • Projects that apply for interconnection after the end of May will not see completed transmission studies until mid-2009

  35. Electric Transmission and Interconnection Transmission Impact Costs • Due to the proposed Generation Interconnection Process Reform, PG&E is not requiring bidders to apply for CAISO interconnection along with their bid. • However bidder will need to assess the potential impacts on the on-line date of its proposed project if it postpones its interconnection application • For initial valuation, PG&E will use cost estimates based on ONE of the following: • One or more CAISO LGIP interconnection studies complete • Use cost estimates from CAISO interconnection studies (FES/SIS/FS) • SIS/FS started, but NOT completed: use any available preliminary results of the SIS/FS for cost estimates • No SIS/FS: use Transmission Proxy Costs (TPC) • PG&E is seeking the ability to request “optional studies” to provide FES level transmission cost information to use in bid evaluation • Would apply to short listed projects without a transmission study under the existing LGIP • PG&E is requiring bidders to apply for interconnection within a week of short listing if they have not already done so

  36. Electric Transmission and Interconnection Resources • ISO Website has application form and complete description of the process. • http://www1.caiso.com/docs/2002/06/11/2002061110300427214.html • PG&E Wholesale Generator Website has contact information • http://www.pge.com/mybusiness/customerservice/nonpgeutility/generateownpower/wholesaleinterconn/

  37. Power Purchase AgreementBidders ConferenceApril 21, 2008

  38. Power Purchase Agreement • Term Sheet provided as Appendix F • Form is structured as natural gas-fired tolling (default structure) • Alternative structures should adjust form accordingly • Contract forms to be posted May 9 • Term 5 – 10 years • Renewables Term may vary

  39. Power Purchase Agreement • Contract Pricing to consist of several components • Capacity Payment Rate ($/kWyr) • Fixed O&M ($/kWyr) • Variable O&M ($/MWhr) • Variable Energy Rate (if applicable -- $/MWhr) • Fired Hour Charge (if applicable -- $/hour) • Seller may apply GDP Implicit Price Deflator as Index • Capacity Payment Rate can only be indexed from date of Agreement to construction financing milestone (Seller defined) • May apply index to a portion of Capacity Payment Rate • Other Pricing components may be indexed from date of Agreement over contract term

  40. Power Purchase Agreement • Maintenance Scheduling • Seller required to notify and schedule with PG&E • No maintenance outages during summer (June – Sept) and Dec – Jan On-Peak without prior consent • Heat Rate (if applicable) • Testing – Summer and Non-Summer • Heat Rate Guarantee • Full load and partial load – 1% deadband • Payment to PG&E if heat rate is greater than guarantee • Bonus to Seller if heat rate is lower than guarantee

  41. Power Purchase Agreement • Availability • Calculated as equivalent availability on a monthly basis after approved maintenance outages • Summer months (June-Sept.) at 98% • 2% reduction in capacity and fixed O&M payments for each 1% below 98% when monthly availability falls below 97% for summer • Non-summer months at 94% • 2% reduction in capacity and fixed O&M payments for each 1% below 94% when monthly availability falls below 93% for non-summer • No Payment of Capacity and Fixed O&M will result if availability • is below 70% in any Summer month • is below 60% in any non Summer month • Bonus • Available during summer months • 102% of capacity payment with availability of 99% or greater

  42. Power Purchase Agreement • Seller to provide information on: • Compensation – Appendix H1 • Technical – Appendix I • Heat Rate • At 100%, 90%, 75%, 50%, and 25% if applicable • At ISO and peak summer conditions • Capacity by Month and Year • Ancillary Service Amounts by Year • Maintenance • Start-up time, shutdown time, ramp rate, etc. • Project Description – Appendix J

  43. Purchase & Sale AgreementBidders ConferenceApril 21, 2008

  44. Purchase & Sales Agreement • Term Sheet provided as Appendix G • Form is structured as a turn-key • Alternative structures should adjust form accordingly • Contract forms to be posted May 9

  45. Purchase & Sale Agreement • Resources: • Peaking • Shaping or Load Following Generation • Seller will develop, permit, design, finance and construct a power plant on a turn-key basis • Seller will prepare plant for commercial operation, then sell to PG&E • Sale must include PG&E option to purchase Long-term Service Agreement

  46. Purchase & Sale Agreement • Seller can submit fixed price or index priced offers • GDP Implicit Price Deflator applies from date of Agreement to construction financing milestone (Seller defined) • Seller identifies portion where index price applies • Payment • 95% at Closing • 5% as much as 15 months after Closing • Offers must include milestone and performance guarantees

  47. Purchase & Sale Agreement • Guaranteed Commercial Operation Date • Guaranteed Base Electrical Output • Base Reliability Guarantee • Guaranteed Peak Electrical Output (if applicable) • Guaranteed Emissions Limits • Guaranteed Net Heat Rate • Other tests

  48. Purchase & Sale Agreement • Peaking Generation Operating Characteristics • Air emission limits at least 4,000 operating hours per year • One hour shutdown to re-start • Three start-stop cycles per day • 15 minute (or less) minimum run time • Local and remote start and stop • NERC and CAISO compliant

  49. Purchase & Sale Agreement • Shaping or Load Following Generation Operating Characteristics • Turndown to 55% (or lower) • AGC and load following from 55% - 100% • Hot-start time <= 90 minutes • Minimum down time <= 60 minutes • Minimum ramp rate of 7% guaranteed capacity rate • Hot shut-down to hot re-start <= 3 hours • 300 annual starts / 25 cold starts • Minimum run-time <= 4 hours • NERC and CAISO compliant

  50. Credit RequirementsBidders ConferenceApril 21, 2008

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