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BIDDERS CONFERENCE July 21, 2009

RENEWABLES PORTFOLIO STANDARD. BIDDERS CONFERENCE July 21, 2009. 2009 SOLICITATION. Agenda. Introduction Commercial Overview Shortlisting Evaluation Methodology Transmission Ranking Costs Interconnection Process Solicitation Documents Q & A. 1. Document Conflicts.

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BIDDERS CONFERENCE July 21, 2009

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  1. RENEWABLES PORTFOLIO STANDARD BIDDERS CONFERENCE July 21, 2009 2009 SOLICITATION

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

  3. Document Conflicts • This presentation is intended to be a summary level discussion of the information and requirements established in the RFO materials (it does not include all of the detailed information in the RFO Materials) • To the extent that there are any inconsistencies between the information provided in this presentation and the requirements in the RFO Materials, the RFO Materials shall govern 2

  4. Commercial Overview 3

  5. RFO Schedule See Section II of the Solicitation Protocol 4

  6. Independent Evaluator • Primary role of the IE is to: • Monitor RFO processes to ensure fair and equal treatment of all potential counterparties • Monitor evaluation processes to ensure PG&E has implemented methodology as described and that bids are treated consistently • Ensure utility ownership and PPA offers are treated consistently • Report on proposed transactions to CPUC when filed for CPUC approval • The IE performs an independent review of all proposals • The IE may review all proposal data and monitor all negotiations • 2009 IE is Arroyo Seco Consulting (Lewis Hashimoto) 5

  7. New for 2009 • Sellers may offer joint development/ownership project • PG&E as Scheduling Coordinator for projects in CAISO control area • Substantially modified PPA to streamline negotiations • Expedited approval process for PPAs up to 4 years in length that meet certain criteria • Changes to credit and collateral • Increased project development security and “capped” damages • Reduced delivery term security • Use of Project Viability Calculator to score offers 6

  8. Eligible RPS offers • Eligible resources • All eligible renewable resources as determined by CEC • Target volumes---1-2% of bundled sales (800-1600 GWh) • Products • As-Available • Baseload • Dispatchable • Delivery term • Seller may bid delivery term of one month up to 20 years or more • Project location & delivery point • Delivery points in CAISO control area • Delivery points outside CAISO control area; Seller to provide price for delivery to CAISO 7

  9. Eligible Offer Structures • Power Purchase Agreement (PPA) • PPA with Buyout Option • Turnkey Ownership - Participants may propose to develop, permit, and construct a facility for purchase by PG&E upon commercial operation • Joint Development/Ownership • Site Offers • For development or expansion by PG&E See Section III and Attachments I and J of the Solicitation Protocol 8

  10. Power Purchase 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/other financing • If not already in price, premium for delivery to CAISO See Section VIII of the Solicitation Protocol 9

  11. PPA Contracts • One form (Attachment H) for most PPAs (as-available, baseload, dispatchable) • Confirm to EEI Master Agreement for short-term contracts up to 4 years (Attachment N) 10

  12. PPA Key Commercial Terms • Contract Price is $/MWh (all-in) for all products except: • Dispatchable - $/kW-year for capacity, $/MWh for energy • Seller receives Contract Price as adjusted by TOD Factors • Delivery Point is PNode for those projects delivering energy onto the CAISO system • Minimum performance criteria apply to all products • Certain non-modifiable terms (highlighted in form PPA) • PG&E is Scheduling Coordinator for projects in CAISO control area • Seller commitment to construction start date and commercial operation date; Provisions for excused delay for force majeure, transmission and permitting See Attachments H and N of the Solicitation Protocol 11

  13. Monthly Period Super-Peak Shoulder Night Jun – Sep 2.20 1.12 0.69 Oct.- Dec., Jan. & Feb. 1.06 0.93 0.76 Mar . – May 1.15 0.85 0.64 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 • Short-term ERRs may price without TOD See Section IX of the Solicitation Protocol 12

  14. Key Changes to 2009 Form PPA • PPA designed to require minimal negotiation • Excused delays in construction start and commercial operation for force majeure, permitting and transmission • 360 days for force majeure and permitting • 540 days for transmission • Cumulative delays not to exceed 540 days • Force majeure no longer an event of default • Guaranteed Energy Production (GEP): PPA specifies minimum delivery amount • 80% of contract quantity for solar • 90% of contract quantity for baseload • P-95 for wind • Shortfalls in GEP can be “cured” with higher generation the following year or payment to PG&E 13

  15. Key Changes to 2009 PPA (cont’d) • PG&E as Scheduling Coordinator (SC) for projects in CAISO control area • Seller responsible for providing meteorological and project availability data PG&E needs to act as SC • PG&E to use data to forecast for intermittent resources and to schedule generation for all resources • As-available projects eligible for CAISO’s Eligible Intermittent Resource (EIRP) program must become EIRP certified and remain eligible for duration of the Delivery Term. PG&E will use EIRP as needed • PG&E bears imbalance risk as long as Seller provides data • Seller subject to forecasting penalty if data not provided 14

  16. Short-Term PPA Key Commercial Terms • Contract Price is $/MWh (all-in) • Price may be fixed $/MWh or • Index price (e.g. NP15, COB) + $/MWh adjustment • Seller may propose price with or without TOD factors • No bid deposit or exclusive negotiations required • Relaxed performance requirements • Sellers in CAISO control area to use Attachment H; See Attachment N for alternate provisions for Sellers outside CAISO control area See Attachment H and N of the Solicitation Protocol 15

  17. Expedited Approval Process (CPUC D.09-06-050) • Establishes price benchmarks and expedited contract review and approval process • CPUC approval process for PPAs up to 4 years • Tier 2 Advice Letter Process • CPUC approval effective in 30 days from advice letter filing unless suspended by CPUC staff • Facility must be in commerical operation or in commercial operation within 6 months of PPA execution • PPA price(including firming and shaping) does not exceed: • – 150% of forward price for a same term, non-renewable energy contract and • – 90% of the MPR for a contract of 10 years • PPA must be based on approved pro-forma contracts with only “minor modifications” 16

  18. Credit • Offer Deposit of $3/kW upon Shortlisting • Initial Project Development Security of $15/kW upon contract execution • Following CPUC Approval, Project Development Security of $100/kW * capacity factor (minimum of $50/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 17

  19. Delivery Term Security Example • Contract Price = $90/MWh • Post-TOD average price = $95/MWh • Contract Quantity = 100 GWh/year • GEP = 80% of Contract Quantity = 80 GWh year Result Minimum expected annual revenue: $95/MWh * 80 GWh = $7.6 million DTS: 20 year contract = $7.6 million DTS: 10 year contract = $3.8 million 18

  20. Credit—Short Term Offers See Sections XX of the Solicitation Protocol 19

  21. CEC Requirements • RPS Eligible Renewable Energy Resources (ERR) must be CEC Certified • CEC Pre-Certification should be obtained prior to construction start • ERRs must participate in CEC Generation Tracking System (WREGIS) • See updated guidebooks at: http://www.energy.ca.gov/renewables/documents/ See Section IV of the Solicitation Protocol 20

  22. Not Part of RPS Solicitation • Resources less than 1.5 MW • Standard tariff available to all eligible renewable resources • http://www.pge.com/b2b/energysupply/wholesaleelectricsuppliersolicitation/standardcontractsforpurchase • Term up to 20 years • Price set at Market Price Referent • Based on combined cycle cost • Determined by CPUC on an annual basis • Levelized price depends on contract term and online date • PG&E’s Proposed 500 MW PV Program • Application included proposed PV PPA at $246/MWh and associated RFO • Currently under review by CPUC • Link to the Application • https://www.pge.com/regulation/PV-Program-PGE/Pleadings/PGE/2009/PV-Program-PGE_Plea_PGE_20090224-01.pdf 21

  23. ShortlistingEvaluation Methodology 22

  24. Three Steps to a Shortlist • Evaluate all valid offers • Provides a first ranking • No transmission cost included • Determine transmission cost • Added to offer’s cost • Second ranking using new cost values • Shortlist chosen from second ranking 23

  25. Evaluation Criteria • Ranking based on combination of Quantitative and Qualitative factors • Quantitative Evaluation • Market Valuation • Transmission Adders • Qualitative Evaluation • Project Viability • Portfolio Fit • Credit • Consistency with RPS Goals • Modifications to Form Agreements See Section XI and Attachment K of the Solicitation Protocol 24

  26. 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. • Locational Marginal Pricing (LMP) multipliers applied • Capacity value is based on: • The net economic carrying cost of a gas-fired power plant • Contribution to PG&E’s Resource Adequacy requirements. 25

  27. Market Valuation (continued) • Valuation of Contract Types • 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. • 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. (Details for the TOA factor specified in the Protocol.) 26

  28. Project Viability All offers will be evaluated and scored using modified version of CPUC Project Viability Calculator (PVC) • Company/Development Team (25%) • Project development experience • EPC experience • Ownership and O&M experience • Technology (25%) • Technical feasibility • Resource quality • Manufacturing supply chain • Development Milestones (50%) • Site control • Permitting status • Project financing status • Interconnection progress • Transmission requirements • Reasonableness of COD (Commercial Operation Date) 27

  29. 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 • Earlier delivery is preferred over later delivery • Dispatchability is preferred 28

  30. Credit • Performance Assurance • Project Development Security • Delivery Term Security 29

  31. Consistency with RPS Goals • CPUC-stated Goals • Legislative Findings • Governor’s Order on biomass • Impact on Water Quality • PG&E’s Supplier Diversity (WMDVBe) WMDVBe: Women-, Minority-, Disabled Veteran-owned Business enterprises 30

  32. First Ranking • Shortlist rankings are relative • No fixed cut-off price • No fixed procurement limit • Based on quantitative and qualitative factors • First ranking done on the basis of market value with adjustments for qualitative criteria • Then, introduce transmission adders 31

  33. 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) • When no Alternative Commercial Arrangement is feasible, and no transmission study results are available, use the TRCR 32

  34. 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 • Ranking is a relative one • Strong offers relative to others will be near the top • Weak offers relative to others will be closer to the bottom • Shortlist chosen from second ranking • Shortlist will err on side of greater inclusion 33

  35. 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 34

  36. Transmission Ranking Costs 35

  37. 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 – Considered in bid evaluation • Network Upgrades • Costs estimates from • CAISO Interconnection Process (ISIS/IFAS) • Transmission Ranking Cost Report See Section X of the Solicitation Protocol 36

  38. Transmission Ranking Cost • For Projects that have not completed the ISIS/IFAS • Solely for bid ranking in this solicitation • Based on proxy transmission facilities or conceptual transmission plan(PG&E, SCE, or SDG&E • Successful bidders must complete the ISO Interconnection Process 37

  39. Malin Captain Jack Oregon California Pacific Gas and Electric Co. (PG&E) Pit 1 Round Mt. Humboldt Caribou Olinda Delta Metering Station Table Mt. Summit Cottonwood Bellota Fulton Rio Oso Wilson Vaca-Dixon Tracy Stagg Tesla Newark Gregg Metcalf Helm Los Banos Gates Panoche Midway Morro Bay Carrizo Plains Southern California Edison (SCE) Renewable resource Cluster 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 • Out of area resources: • North:Round Mountain • South:Midway • East: Summit 38

  40. Table X.1 Transmission Ranking Cost Where PG&E is the Purchaser * Cost of Proxy Voltage Support Devices are to be prorated in proportion to the size of the project. 39

  41. Example • Two Offers received: • A: 300 MW (base load) • B: 300 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." 40

  42. Ways to avoid triggering Next Level of Transmission Ranking Cost Attachment D to the Protocol • Energy Pricing Sheet • Optional “Dispatch Down” or “Curtailment” 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 Curtailment or Dispatch Down provision. 41

  43. Interconnection Process 42

  44. Generation Interconnection Study Process • Interconnection process must be complete in order for generator to deliver power to the grid and meet obligations of RPS contract • Generator responsible for all generation interconnection costs • Generator responsible for timely applications with CAISO and timely completion of the process • Not part of RPS Solicitation • Process should be started early 43

  45. Generation Interconnection Study Process • Transmission Interconnections • All applications must be submitted with the CAISO • Generators less than or equal to 20 MW, Small Generator Interconnection Procedures (SGIP) • Generators greater than 20 MW, follow Large Generator Interconnection Procedures (LGIP) • Information on the SGIP 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/includes/docs/pdfs/b2b/newgenerator/wholesalegenerators/wdt.pdf 44

  46. Small Generator Interconnection Procedures (SGIP) Interconnection Agreement (SGIA) Interconnection Facilities Study (IFAS) Negotiation (30 BD) Study Process (45 BD) Interconnection System Impact Study (ISIS) Study Process (45 BD) Interconnection Feasibility Study (IFS) Study Process (30 BD) Interconnection Request (IR) Cumulative time >= 6 months 45

  47. Large Generator Interconnection Procedures (LGIP per GIPR) Interconnection Agreement (LGIA) Negotiation (60 CD) Phase II Cluster Study Study Process (1 Year) Phase I Cluster Study Interconnection Request (IR) Study Process (1 Year) Cumulative time >= 2 Years 46

  48. Solicitation Documents 47

  49. Offer Submittal • Offers must be received by PG&E by Monday, August 24, 2009 at 10 a.m. (PDT) • Both Electronic and Hard Copies • Electronic copies - two (2) flash drives • Hard copies (3 Bound & 1 Unbound) delivered to: RPS Solicitation Electric Supply Department Pacific Gas & Electric Company 245 Market Street, 13th floor San Francisco, CA 94105 48

  50. Information due August 24 • Signed RPS Solicitation Protocol Agreement (Attachment A) • Fully Completed Offer Form (Attachment D) • FERC Order 717 Waiver (Attachment F) • Applicable Form of PPA (Attachment H or Attachment N), 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 49

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