California Cap-and-Trade Program Takes Shape
After a year and a half of protracted negotiations among utilities, wholesale generators and consumer advocates, the California Public Utilities Commission approved a global settlement in December about how the federal Public Utility Regulatory Policies Act—or “PURPA”—will apply in the state.
Among other things, the settlement will resolve outstanding pricing disputes with independent power plants, called qualifying facilities or “QFs,” from whom PURPA requires utilities to buy electricity, establish the methodology for future energy pricing based on short-run avoided costs or “SRACs” for such power plants, establish a process for future procurement of power from QFs and CHPs—combined heat and power, or cogeneration, facilities that meet certain efficiency and environmental standards under federal and California law—and allow utilities to avoid a mandatory purchase obligation under PURPA for QF projects above 20 megawatts in size.
PURPA is a federal law passed in the late 1970s that requires utilities to offer to purchase the output from QFs —generators up to 80 megawatts in size using renewable fuels and cogeneration facilities of any size—at the utility’s “avoided cost,” or what it would otherwise cost a utility to produce the power itself or procure it from another source.
Cogeneration facilities are facilities that simultaneously and sequentially produce electricity and a form of useful thermal energy such as steam or heat.
CHPs are cogeneration facilities that also meet more stringent California environmental and efficiency standards under a state law called AB 1613.
CHP systems under California law must be designed to reduce waste energy, must preserve at least 60% of the energy content in the fuel they use during conversion into electricity, have NOx emissions of no more than 0.07 pounds per megawatt-hour, be sized to meet the eligible customer generation thermal load, operate continuously in a manner that meets the expected thermal load and optimizes the efficient use of waste heat, and be cost effective, technologically feasible and environmentally beneficial.
Specifics of the Settlement
Dropping pending claims if FERC eliminates the purchase obligation:
Under the global settlement, the investor owned utilities agreed to drop claims for retroactive adjustment of payments made under certain QF contracts, provided the Federal Energy Regulatory Commission grants a request by the utilities to terminate their mandatory purchase obligations for QFs above 20 megawatts in size. The settling parties have agreed not to challenge this request. Under an amendment to PURPA in 2005, FERC was given the authority to terminate the mandatory purchase obligation if it found that the relevant energy markets are workably competitive. It is expected that FERC will grant this request.
Impact on existing PPAs:
Existing QFs with “legacy PPAs”—meaning any power purchase agreement that is in effect at the time the new settlement goes into effect—will have the option to choose to enter into a legacy PPA amendment within 180 days after the settlement takes effect. The Federal Energy Regulatory Commission must approve certain aspects of the settlement before it can take effect. This is expected in mid-2011.
The legacy PPA amendment must allow the QF to choose an energy pricing methodology option going forward until January 1, 2015. Independent generators with fixed energy rates in their PPAs will be allowed to continue to collect them until the rates expire.
There are least five pricing options, all of which are tied to the utility’s delivered cost of natural gas. The generator can switch to the new SRAC methodology, which has fixed, declining heat rates, a variable operation and maintenance component, an adjustment based on location in relation to load and a price adjustment if greenhouse gas or “GHG” costs are imposed on the facility, all until December 31, 2014, after which the SRAC will be tied only to a formula with energy market heat rates, called the “settlement SRAC.” Another option uses the same formula but somewhat higher heat rates and no GHG cost adder. The third option is to use the same formula but with heat rates between the heat rates in the first two options and a fixed greenhouse gas payment of $20 a metric ton for greenhouse gas emissions allowances used by the seller of the electricity. The next option is the same, but with the GHG allowance costs tied to actual GHG costs imposed on facility capped at $12.50 per metric ton. The last option is to choose a 90-day negotiation period to see whether parties can turn the PPA into a tolling agreement on agreed terms.
If a QF chooses not to enter into a legacy PPA amendment, then the pricing under the existing PPA contract will be the settlement SRAC.
Under the terms of the settlement, once the term of a legacy PPA expires, the utility will have no obligation to purchase power from the QF if it has a generating capacity above 20 megawatts, but the utilities have agreed to conduct solicitations for QF output. QFs below 20 megawatts will be entitled to SRAC pricing and capacity payments determined by the CPUC.
Impact on existing CHP projects:
Cogeneration projects with existing PPAs with utilities under a legacy PPA will be able to enter into a transition PPA until July 1, 2015. The energy will be priced at the settlement SRAC. The capacity price will be $91.97 per kW-year for firm capacity and $41.22 per kW-year for as-available capacity, subject to annual escalation.
What happens in the longer term:
There will be no standard offer PPAs for QF projects above 20 megawatts. However, the three investor-owned utilities in California (Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric) have agreed to issue a series of solicitations for a combined target of 3,000 megawatts of QF and CHP capacity. The solicitations are supposed to result in PPAs that will meet both the megawatt target and greenhouse gas reduction goals specified under California law. The California Air Resources Board, in implementing the state’s greenhouse gas law known as AB 32, set a target of installation of 4,000 megawatts of CHPs by the end of 2020. The initial program period of the Settlement is 48 months from the date the settlement takes effect. If less than 3,000 megawatts of power contracts are signed by the end of the initial program period, then the unprocured amount will be rolled over into a second program period to reach the 3,000-megawatt target.
Although not addressed in the settlement agreement, renewable QFs will continue to be eligible to participate in solicitations the investor-owned utilities are required to run to satisfy the state renewable portfolio standard.
What happens in the shorter term:
The settlement agreement includes five pro forma power purchase agreements.
There is a form of legacy PPA amendment, which, as noted earlier, relates to optional energy pricing that a QF with an existing PPA can elect to sign within 180 days of the effective date of the settlement.
There is a transition PPA that is available to any existing CHP facility with an existing PPA. The transition PPA term will begin on the expiration of the existing PPA and may be terminated upon 180 days’ notice when a CHP facility has signed a new PPA resulting from either a solicitation or a bilateral negotiation.
There is a CHP request-for-offers PPA that will be used to solicit competitive offers from CHP generators. Each IOU must initiate a request for offers within 180 days after the effective date of the settlement for purchases from existing, new or expanded CHP facilities over five megawatts in size using this form of PPA. To be eligible for the solicitation, the CHP must satisfy the qualifying cogeneration facility criteria under FERC’s regulations implementing PURPA. The term of the PPA will be up to seven years or 12 years, depending on the type of facility and credit requirements that the facility owner agrees to provide.
Alternatively, a CHP facility over 20 megawatts in size may sign an “as-available CHP PPA,” provided that its average annual deliveries do not exceed 131,400 mWhs, the project host consumes at least 75% of the total electricity generated by a topping-cycle facility or at least 25% of the total electricity generated by a bottoming-cycle facility. Fora topping- or bottoming-cycle facility using supplemental firing, the facility must meet at least a 60% efficiency standard. The seller under an as-available CHP PPA will get an as-available capacity price and a time of delivery energy price and must provide performance security. If the seller is selected later in a solicitation, the seller can terminate the as-available CHP PPA.
Finally, there is also a standard form PPA that will be available for QFs that are up to 20 megawatts in size, whether or not the QF has submitted an offer in the CHP request for offers or seeks alternative contracting options. This PPA will use the settlement SRAC for the energy price and contain specified as-available or firm capacity payments.
The settlement also gives the investor-owned utilities additional flexibility to undertake bilateral contracting, use feed-in tariffs authorized by California law AB 1613 (for CHP projects), continue the PURPA program for QFs smaller than 20 megawatts in size and allocate up to 10% of the CHP capacity for utility-owned projects for GHG reduction purposes but not for meeting the 3,000 MW requirement.
The investor-owned utilities insisted that their agreement to procure new resources in this way must be conditioned on the assurance by the CPUC of a non-bypassable passthrough of PPA payments. The CPUC granted this request in its order approving the settlement.
Elimination of the IOU mandatory purchase obligation:
With the approval of the global settlement, the investor-owned utilities will file an application with FERC requesting termination of their mandatory purchase obligation under PURPA for projects with a net capacity above 20 megawatts. The other settling parties can comment on, but have agreed not to protest, the application. The settlement agreement also gives the other settling parties the right to ask FERC to reinstate the mandatory purchase obligation under PURPA if an investor-owned utility breaches its obligations under the proposed settlement or the CHP program is not successfully implemented. In the event FERC reinstates the mandatory purchase obligation, the obligation of the utilities under the settlement agreement to issue requests for offers from CHP projects to meet megawatt and GHG targets would be suspended.