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California Combined Heat & Power: Barriers to Entry and Public Policies for the Maintenance of Existing & the

California Combined Heat & Power: Barriers to Entry and Public Policies for the Maintenance of Existing & the Development of New CHP. Industrial Energy Consumers of America (ICEA) Hilton San Francisco Financial District 750 Kearny Street • San Francisco, California 94108 June 21, 2011.

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California Combined Heat & Power: Barriers to Entry and Public Policies for the Maintenance of Existing & the

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  1. California Combined Heat & Power:Barriers to Entry and Public Policies for the Maintenance of Existing & the Development of New CHP Industrial Energy Consumers of America (ICEA) Hilton San Francisco Financial District 750 Kearny Street • San Francisco, California 94108 June 21, 2011

  2. Overview • The long recognition of barriers to entry for CHP, and regulatory response • What are barriers to entry? • The CPUC CHP Program Settlement – a policy pier, not a bridge • What is and isn’t accomplished in the settlement? • Long Term Procurement Policies for CHP and Self Generation • Departing Load Charges – unique to California – a major economic barrier to new development • Carbon Cost Recovery Barriers and Unbalanced Risks • IOU Proposed “Suspension” of CPUC Rule 21 Interconnection and the CAISO Interconnection Burdens

  3. Regulatory Recognition of Barriers to Entry for CHP

  4. A Brief History • PURPA was a response to barriers to entry • 1973 Arab oil embargo caused skyrocketing oil prices • California utilities relied on oil fired generation • Natural gas in short supply with and uncertain supply future • Utility generation answer – large central station coal and nuclear (along with extraordinary construction cost overruns) • The Alternative – move beyond the traditional role of utilities as the sole providers of new generation – Qualifying Facilities QFs and independent power. • Must Take obligations and Avoided Cost pricing broke down utility barriers of non-negotiation, refusal to buy, interconnect or provide reasonable back up power.

  5. A Brief History (2) • 1982 CPUC Decisions (D.91109 and D.91107 for PG&E and D.82-12-055 for SCE) penalized utility for erecting barriers and failing to promote cogeneration development • Thereafter Standard Offer Contracts were established • By 2003 CHP produced about 17% of the total IOU annual energy requirements and about 5% of California’s energy requirements through self generation • Energy Policy Act of 2005 and Section 210(m) undermined must take and avoided cost obligation if “a market” exists • There has been and continues to be a noted decline in CHP capacity as the 1980’s contracts terminate and California established no new policy to develop CHP

  6. Recognition of Barriers and Policy for CHP • FERC Order 888: “this Rule will not insulate a utility from the normal risks of competition, such as self-generation, cogeneration or industrial plant closure, that do not arise from the new availability of nondiscriminatory open access transmission. Any such costs … [are not] stranded costs.” • CPUC: adopted the CHP Program for CHP’s “resource diversity, fuel efficiency, greenhouse gas (GHG) emissions reductions, and other benefits and contributions.” D.10-12-035 • CARB Scoping Plan: “The CPUC and CEC should eliminate all non-bypassable charges for CHP systems regardless of size or interconnection voltage and standby reservation charges.”

  7. Recognition of Barriers and Policy for CHP (2) • CEC 2009 IEPR: “The barriers to increased penetration of CHP technologies have been identified repeatedly in past IEPRs, but little progress has been made.” Since 2003, IEPRs have called for increased CHP and elimination of barriers to entry including departing load charges. • Governor Brown’s Jobs for the Future platform: CHP is “much more efficient than traditional power plants.… With the right incentives, we can increase [CHP] by 6,500 MW over the next 20 years.” • California Public Utilities Code §372(a) – It is the policy of the state to encourage and support the development of cogeneration as an efficient, environmentally beneficial, competitive energy resource that will enhance the reliability of local generation supply, and promote local business growth.

  8. Barriers to Entry; What are they?

  9. Barriers to Entry for CHP • According to a 2002 CEC report, barriers to entry include “high fees, long approval processes, insurance requirements, exit fees, and capital costs.” • Others may be: • Capacity and energy pricing (term for recovery or comparable recovery) • Credit and collateral (insurance of delivery) burdens • Unavailability of commercial terms and conditions – contracts • Long and costly contract negotiation processes • New risks of recovery – Carbon Cost Recovery (Green House Gas) • Interconnection – costs, timing, access and regulatory authority • Conditions that render projects non-commercial or unable to compete with utility generation resources – but isn’t that an electric “market”?

  10. CPUC CHP Program Settlement

  11. CHP Program Settlement – What does it Resolve? • Establishes a near term (Initial Program Period) CHP procurement target of 3,000 MW – essentially existing facilities • Defines a CHP “market” as CHP resources – a CHP only RFO • Resolves litigation over past retroactive pricing claims • Establishes Transition PPAs – temporary safe harbor – for existing CHP contracts including avoided cost pricing

  12. CHP Program Settlement – What does it Resolve?(2) • CHP only RFO procurement for 3,000 MW, but excused performance possible and all other CHP procurement “counts” • State CHP program, as a replacement for the Federal PURPA program • Establishes benchmark for GHG benefits and future accounting to meet CARB goals • Establishes pro forma PPAs and reporting for CHP procurement progress (MWs & GHG)

  13. CHP Program Settlement – What remains Unresolved? • “Jump ball” for CHP procurement after 2015 – CPUC LTPP process • Contracts for existing CHP 7 years; contracts for new CHP 12 years • No long term policy chills investment • Pro forma contracts will not work for all CHP projects; negotiations with utilities have been barriers to entry • RFO will likely require negotiated agreements

  14. CHP Program Settlement – What remains Unresolved? • CHP parties accepted a termination of must take obligation under federal law • Under 20 MW CHP exposed to spot electric market • Over 20 MW must be successful in RFO bid process • Future procurement, CAISO tariff requirements and RFO success uncertain

  15. CHP Program Settlement – Conclusion • A Pier; not a Bridge • CHP still needs a Bridge to a long term future • Open issues over the procurement standards for CHP after the 3,000 MW Initial Program Period (48 months) • The Second Program Period ends in 2020 • What Program is in place after the initial contracts and after 2020? • Likely effective date in Mid-July and first CHP RFO in October 2011

  16. DEPARTING LOAD CHARGES

  17. Departing Load Charges – 5/4/2011

  18. PG&E E-20T DL Charge: $16.96 MWh

  19. PG&E E-20T PPP: $11.25 MWh

  20. Growth in PPP

  21. Departing Load Charges - Impact • Departing Load Charges burden project economics and impair a project’s ability to compete internally for capital with other projects • Assuming an installed cost of $1,000/kW, all else being equal, a CHP project with an 11% hurdle rate serving a load with a 90% load factor would require a return of nearly 26% to cover departing load charges in PG&E’s service territory and meet the hurdle rate • Reasonable reduction of CGDL charges would be lost in the rounding in remaining bundled customer rates

  22. Key Exemptions • Categories of exemption for CGDL: • DWR power costs • Procurement non-bypassable charges • Competition Transition Charge • New CHP program charges • Categorical exemption for new load served by a “direct transaction” without leaning on the utility system • Categorical exemption for load reductions in the normal course of business

  23. Eliminating Energy Efficiency and Bond Charges Reduce CGDL Charge to $8.51 MWh

  24. CARBON COST BARRIER

  25. Barrier: Carbon Cost Recovery • CARB cap-and-trade (C/T) benchmarking methodology carries the potential to create disincentives for moving from grid power purchases to gas-fired self-generation • Replacing grid power purchases with gas-fired self-generation or supplemental firing of waste heat recovery generators converts indirect emissions for electricity consumption to direct emissions • As a result, self-generation increases the number of allowances that must be surrendered by the regulated party to cover direct emissions • CARB regulations are unclear whether a customer utility-provided carbon cost rebate would be eliminated in moving from grid power to self-generation or whether the customer’s benchmark award of free allowances under C/T would be increased

  26. Barrier: Carbon Cost Recovery (2) • Absent adjustments, the electricity consumer will be disadvantaged with self-generation when the spread between direct emissions cost/coverage is greater than the spread between indirect emissions cost/coverage on its former rate schedule • A variety of factors will influence this spread: • Will direct emissions coverage be updated or remain at baseline? • To what extent will coverage decline as a result of declining assistance factors or the cap decline? • To what extent will CARB or the CPUC allow utility allowances to follow the former customer when it departs the utility system? • Will electricity usage increase or decline?

  27. Simplified Carbon Cost Example Grid Purchases Self-Generation 100,000 MWh annually $20 MT carbon price .4 MT/MWh emissions rate No coverage of new direct emissions cost (no update) Utility rebate does not follow the customer Carbon cost to customer: $800,000 • 100,000 MWh annually • $20 MT carbon price • .3 MT/MWh utility emissions rate • 90% carbon cost coverage through utility rates • Carbon cost to customer: $60,000

  28. Potential Carbon Cost Solutions • Utility rebate amount follows the customer when self-generation is installed • CARB updates free allowance allocation to the customer by adding to the customer’s free allowance benchmark award an amount equal to: • Actual or estimated self-generation emissions or • Former utility value converted to MT ($ divided by utility average grid emissions rate) • To prevent impact to others in sector of increased allowance allocation to migrating customer, CARB could transfer allowances from utility sector to customer’s sector

  29. Interconnection – A Renewed Barrier to Entry? • IOU Advice Letter Filings SCE 2593-E, PG&E 3864-E and SDG&E 2262-E) on June 17, 2011 (last Friday) • Filings Seek suspension of State jurisdictional Rule 21 interconnections • Substitute “temporarily” the CAISO generator interconnection and Resource Adequacy tariff obligations • Uncertain future for interconnection in light of queues for “dependable capacity/generation” studies – 2013 and beyond for new filings • Conflict with FERC jurisdictional rulings on QF interconnection – Florida Power & Light Docket No. EL10-43-000, Nov. 30, 2010 • Conflict with CPUC position on State jurisdiction over QF interconnection • Is the CAISO in charge? Is customer generation now another form of utility regulation and compliance?

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