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 and D for PG&E and D 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
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
Rate ($/MWh)
Exemption
PG&E
E-20T
Public Purpose Program Charge
$11.25
None
Nuclear Decommissioning
$0.66
Competition Transition Charge (CTC)
Exempt [$5.23]
Public Utilities Code §372
DWR Bond Charge
$5.05
PCIA
(DWR and Utility components 2010, 2011 Vintages)
Exempt [$11.42]
URG: D ; Res. E-4226
DWR: D
PG&E Energy Cost Recovery Amount
Exempt [$4.72]
D , D
QF CHP Settlement
Exempt [TBD] D
TOTAL APPLICABLE, KNOWN PG&E NBCs
$16.96
SCE
TOU-8-
Sub
$7.23
$0.64
Exempt [$3.22]
(DWR and Utility components, 2010 Vintage)
Exempt [$4.41]
SCE Historical Procurement Charge
customer-specific; paid D
New System Generation Charge (CAM NBC)
Exempt [$0.91]
D ; D
TOTAL APPLICABLE, KNOWN SCE NBCs
$12.92

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
.3 MT/MWh utility emissions rate
90% carbon cost coverage through utility rates
Carbon cost to customer: $60,000
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

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. EL , 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?