3. Threshold Issues
3.1. Commission Authority to Establish AB 1613 Purchase Price
The primary issue of dispute in this proceeding has been the extent to which the Commission has authority to establish the price to be paid by electrical corporations to eligible CHP facilities. PG&E, SCE, and SDG&E/SoCalGas (collectively, the investor-owned utilities or IOUs) assert that since power sold under AB 1613 would be considered a wholesale transaction, the Commission has limited authority in setting the price for this feed-in tariff (FIT). They note that under the Federal Power Act (FPA), the Federal Energy Regulatory Commission (FERC) has sole jurisdiction to set rates for wholesale power sales to and by public utilities, unless the generator is a qualifying facility (QF).3 Therefore, the IOUs assert that if the AB 1613 CHP is not a QF, the price is solely within the FERC's jurisdiction and must be based on prices in the California Independent System Operator (CAISO) market.4 To the extent an AB 1613 CHP is a QF, the IOUs maintain that the Commission may only set prices at utility avoided cost.5 We disagree with the IOUs' arguments that we are limited in our ability to set prices under AB 1613, because the IOUs mischaracterize the program that is being established.
We disagree with the IOUs' assertions that CHP systems participating in the AB 1613 program should be considered QFs. AB 1613 does not make any reference to the PURPA requirements, nor does it require that a CHP obtain QF status in order to be eligible to participate under AB 1613.6 Rather, eligibility is based on meeting and maintaining specified size limitations and standards set by statute and the CEC. Moreover, we note that the purposes of PURPA and AB 1613 derive from entirely different policy concerns. PURPA was enacted to address the nation's energy crisis and to reduce dependence on foreign oil.7 When the FERC adopted rules implementing PURPA, FERC recognized that PURPA did not preempt State environmental laws, including State zoning, air, water, and other environmental quality laws.8
In contrast to PURPA, AB 1613 was enacted to further environmental objectives. Indeed, purchases of power under this program will be incorporated in a utility's procurement obligations "to the extent that it is cost effective compared to other competing forms of wholesale generation, technologically feasible, and environmentally beneficial, particularly as it pertains to reducing emissions of carbon dioxide and other greenhouse gases."9 Thus, whether or not there are some similarities between how the Commission would process claims under AB 1613 with how it would process claims under PURPA, this would not be a basis for finding AB 1613 preempted. Indeed, notwithstanding the requirement under section 210 of PURPA, that state commissions must administer federal standards concerning QFs, the U.S. Supreme Court held that PURPA did not violate the Tenth Amendment of the U. S. Constitution, because state commissions already had "jurisdiction to entertain claims analogous to those granted by PURPA."10
We further disagree with the IOUs' arguments that the Commission is regulating the price of excess electricity sold under this program. AB 1613 is not regulating wholesale generators or marketers but the electrical corporations, which purchase electric energy and then sell it in the retail market in California. Under section 201(b) of the FPA, the FERC regulates the sellers of electric power in the wholesale electricity market. However, as the Commission explained in D.07-01-039 at p. 203: "FERC regulates the wholesale sellers, not the resource portfolios, including procurement choices, of the buyer. As FERC has stated in numerous decisions, FERC leaves the reasonableness of the procurement decisions to the state commissions, because FERC does not view its `responsibilities under the Federal Power Act as including a determination that the purchaser has purchased wisely or has made the best deal available.'"11
Further, the policy objectives of AB 1613 are to:
[(a)] advance the efficiency of the state's use of natural gas by capturing unused waste heat, and in doing so, help offset the growing crisis in electricity supply and transmission congestion in the state.
[(b)] reduce wasteful consumption of energy through improved . . . utilization of waste heat whenever it is cost effective, technologically feasible, and environmentally beneficial, particularly when this reduces emission of carbon dioxide and other carbon-based greenhouse gases.12
AB 1613 directs the Commission to establish an FIT for excess electricity to achieve these policy objectives. Unlike programs promoting the purchase of energy from certain types of generators, this FIT is an incentive structure to encourage the adoption of energy efficiency measures with beneficial environmental attributes - in this case, generation of excess electricity from what would have otherwise been waste heat. Thus, this program will enhance the efficiency of operation of an existing class of industrial boilers by providing incentives for their owners to install heat recovery steam generators and turbines at the tail end of these existing units. This will capture and make useful the energy already produced by boilers, which until now, had been discharged to the atmosphere as waste heat.13 Moreover, AB 1613's policy goal to reduce carbon-based emissions is part of the state's overall objective to reduce GHG emissions, as articulated in AB 32.14
Under AB 1613, a CHP system may only participate if it meets certain requirements, including complying with the CEC's guidelines for certification, meeting an oxides of nitrogen (NOx) emissions rate standard of 0.07 pounds per megawatt-hour (MWh) and a minimum efficiency of 60 percent, complying with the GHG emission performance standard, and continuing to meet or exceed the efficiency and emissions standards throughout its operation.15 Under the CEC's draft Guidelines for Certification of Combined Heat and Power Systems Under the Waste Heat and Carbon Emissions Reduction Act, Public Utilities Code Section 2840 et seq. (CEC Staff Draft Guidelines) issued October 2009, the CEC has proposed various standards that a CHP facility must meet in order to receive certification.16 In addition to the efficiency and emissions standards specified under § 2843, a CHP facility would need to meet certain net electrical generating capacity, thermal energy utilization, and fuel savings standards. The CEC Staff Draft Guidelines further recommends annual reporting by the CHP owner/operator to ensure ongoing compliance. Finally as discussed in Section 3.4 below, we shall be setting an initial statewide cap of 500 MW for the program.
The IOUs, particularly SCE, have argued throughout this proceeding that the FERC has already affirmed its authority to set prices for programs such as AB 1613. We do not find these arguments persuasive. The FERC decisions relied on by the IOUs affirm that the FERC has sole jurisdiction to set rates for wholesale sales in interstate commerce in order to ensure competitive wholesale energy markets. However, as explained above, AB 1613 is encouraging the development of more efficient CHP systems that would provide environmental benefits. In order to achieve this objective, the Commission is directing the electrical corporations to incorporate these systems into the utilities' procurement obligations. Consequently, AB 1613 requires the Commission to treat these incentives for new CHP systems to reduce GHG emissions as a component of the Commission's regulation of the procurement practices of the electrical corporations, and the Commission is directing IOUs subject to its jurisdiction to offer to purchase excess electricity from eligible CHP systems under this program. Under section 201(b) of the FPA (16 U.S.C. § 824(b), Congress preserves the states' authority over such retail sales service, including determining the composition of utility portfolios subject to their jurisdiction.17 Indeed, the FERC has acknowledged that with regard to the retail electric market, "state regulatory commissions and state legislatures have traditionally developed social and environmental programs suited to the circumstances of their states. Nothing in [FERC's Order No. 888] is inconsistent with traditional state regulatory authority in this area."18 For example, we noted in D.08-03-018
There is no "field preemption" [in the regulation of GHG emissions] because in enacting the FPA, Congress did not intend, either explicitly or implicitly, to occupy the field of environmental regulation of the power sector. California will be regulating in a field (GHG emissions and their reduction) that Congress has not even addressed in the FPA, nor is there any suggestion in the FPA or in its administration that Congress intended to forbid states from enacting GHG regulations on their own. The regulations we are recommending to ARB are not directed at wholesale rates or service or the other terms and conditions of wholesale sales that are the focus of the FPA. Rather, they are directed at reducing GHG emissions associated with the generation of electricity in California and with ultimate electric service within California, matters left to the discretion of the states. Nothing in the part of the FPA at issue here or its legislative history suggests that Congress intended to occupy the field of environmental regulation, which is the sole purpose of the California law and proposed regulations at issue here.19
The FERC is well aware that certain states require that the resource portfolios of their state-regulated utilities include generation and procurement from sources that will cause minimal damage to the environment. Thus, it has recognized the authority of the states to regulate in the area of GHG reductions.20 Moreover, the FERC has recently determined that energy efficiency programs should be within the state's jurisdiction and stated that "CAISO should respect California's determination that energy efficiency and demand-side resources receive the highest priority in meeting future reliability needs."21
Finally, a memorandum issued by the Obama Administration to the heads of Federal Executive Departments and Agencies directs these agencies to avoid preempting states in their implementation of state initiatives, such as environmental measures.22 In the Executive Memorandum, President Obama quotes Justice Brandeis in explaining that "[i]t is one of the happy incidents of the federal system that a single courageous state may, if its citizens choose, serve as a laboratory; and try novel social and economic experiments without risk to the rest of the country."23 Similarly, in describing Congress' intent within a few years after the enactment of the FPA, the Supreme Court explained:
Congress is acutely aware of the existence and vitality of state governments. It sometimes is moved to respect state rights and local institutions even when some degree of efficiency of a federal plan is thereby sacrificed...It may, too, think it wise to keep the hand of state regulatory bodies in this business, for the "insulated chambers of the states" are still laboratories where many lessons in regulation may be learned by trial and error on a small scale without involving a whole national industry in every experiment. 24
These factors all support a conclusion that setting the FIT contemplated under AB 1613 would be within the Commission's authority. Although the program will result in the California utilities' purchases of excess electricity, the program would serve the public interest by encouraging additional efficient use of energy and the resulting reduction of GHG emissions. Additionally, the program does not - and does not purport to - regulate the conduct of sellers. No seller is required to participate in this program and the program does not restrict the ability of any seller to sell its excess electricity in the CAISO market. The FIT is simply an option provided by the retail electric utilities available to the sellers, as an incentive to meet California's environmental goals.
Thus, the Commission could still set the price for California utilities to offer to pay sellers to encourage development of these highly efficient CHP facilities in order to reduce GHG emissions.
3.2. Indifference
Pub. Util. Code § 2841(b)(4) states that ratepayers not utilizing CHP systems should be "held indifferent to the existence of this tariff." Parties were asked how indifference should be determined under AB 1613. All parties state that establishing an "appropriate" level of pricing will ensure that ratepayers are indifferent to the existence of an AB 1613 tariff. However, there are varying opinions on what would be considered an appropriate level.
SCE maintains that prices paid for power in the day-ahead CAISO market are the appropriate measure for ratepayer indifference because "the CAISO wholesale market is where SCE would buy power if an AB 1613 system did not produce power as expected."25 SDG&E/SoCalGas contend that ratepayers not utilizing the CHP systems would be held indifferent only if the price is based on utility avoided cost or the CAISO day-ahead market, since these are the costs the utility would have otherwise paid for energy and capacity.26 PG&E agrees with SDG&E/SoCalGas and further states that certain non-price contract provisions, such as operational issues, may also result in higher costs to non-CHP customers. Therefore, it contends that any costs resulting from these non-price provisions must also be accounted for to ensure non-CHP customers will be held indifferent.27
Fuel Cell maintains that customer indifference should not be defined by reference to utility avoided costs since QF pricing under PURPA is administratively established and must comply with Federal regulation.28 It points out that in contrast, AB 1613 specifies the criteria for participation in the program and that there is no requirement that a CHP facility have QF status. Fuel Cell argues that indifference under AB 1613 should take into account not only the price paid for power, but also all costs and benefits associated with AB 1613. It states these possible costs and benefits would include any above- or below-market costs for power, price paid for or value received from GHG emission reductions, resource adequacy benefits, and benefits associated with added distributed generation.
CCDC maintains that market-based pricing, such as the Market Price Referent (MPR), would ensure that ratepayers would be held indifferent to the existence of an AB 1613 tariff. It notes that the MPR has been used to determine the reasonableness of renewable energy contracts. Thus, similar to the finding of reasonableness in the context of renewable procurement, AB 1613 contracts based on MPR pricing could be considered "reasonable per se."29 CCDC further asserts that AB 1613 contemplates that there will be benefits associated with the sale and purchase of excess energy. Thus it argues that any market-based pricing mechanism also includes the benefits of CHP to ensure indifference.
We agree with parties that customer indifference is achieved when ratepayers not utilizing the CHP systems are no worse off, nor any better off, as a result of power purchased pursuant to AB 1613. While one could argue that indifference would be achieved by setting price equal to an electrical corporation's avoided cost or the market price, we do not believe that such a narrow application would be the appropriate measure in this instance. As we have previously discussed, the intent of AB 1613 is to reduce GHG emissions and other pollutants through the development of small, highly efficient CHP systems. Consequently, customers not utilizing these CHP systems will be receiving not only electricity from these systems, but also certain societal benefits.30 As such, in order to ensure that customers not utilizing the eligible CHP systems are no better off, the price paid under this program should include the value of these benefits.
PG&E contends that since any potential environmental or locational benefits associated with energy sold under AB 1613 have not been quantified, there would be no basis for imposing additional costs on customers.31 We disagree that these benefits have not been quantified. As discussed below, the price for power under the AB 1613 program will include a location bonus and costs for GHG attributes. These costs would reasonably approximate the value of the benefits obtained under the program.
In light of these considerations, we find that customer indifference under AB 1613 would not be achieved if the price paid under the program only reflected the market price of power. As discussed, since customers who are not utilizing the eligible CHP system will receive environmental and locational benefits from these systems, the price paid for power should also include the costs to obtain these benefits.
3.3. Benefiting Customers
Pub. Util. Code § 2841(e) requires that the costs and benefits associated with the new CHP tariff be allocated to all "benefiting customers" and that this term may include "bundled service customers of the electrical corporation, customers of the electrical corporation that receive their electric service through a direct transaction, as defined in [Pub. Util. Code § 331(c)], and customers of an electrical corporation that receive their electric service from a community choice aggregator, as defined in [Pub. Util. Code] Section 331.1."32 Parties were asked to comment how broadly this term should be construed for purposes of allocating the costs and benefits associated with the AB 1613 tariff.
The IOUs advocate the broadest definition of "benefiting customer." SCE states that "[t]o the extent the purpose of AB 1613 is to reduce carbon emissions, all residents of the state are "benefitting customers," and the net costs should be spread equally among all bundled service customers, direct access (DA) customers and community choice aggregation (CCA) customers."33 In support of its proposal, SCE notes that D.06-07-029 had allocated the benefits and costs of new generation to all customers in an IOU's service territory. PG&E agrees with SCE, but notes that since it is not clear what benefits would result from the AB 1613 program, benefits should be allocated based on each customer group's contribution to payment of above-market costs.34
Irrigation Districts assert that the definition of "benefiting customer" is limited under AB 1613 to only three categories of electrical corporation customers: bundled service customers, DA customers, and CCA customers.35 They note that since § 2841(e) only identifies three categories of customers, it would violate the rules of statutory interpretation to include customers of publicly owned utilities (POUs) in the term "benefiting customers." Irrigation Districts list additional reasons why POU customers should not fall within the definition of "benefiting customer." First, they note that POU customers generally receive electric and distribution service from a publicly owned utility and no services from the electrical corporation. Further, they state that POU customers do not fall within the definition of a DA customer as defined in § 331, or a CCA customer, as defined in § 331.1. Finally, Irrigation Districts state that POU customers who were formerly bundled service customers have, with the exception of large municipalizations, been excepted from any non-bypassable charges associated with "new world generation."36 Thus, they contend that since generation contracted under AB 1613 is "new world generation," even these POU customers should not be allocated any costs associated with it.
CCDC also argues that the Commission may only consider three categories of electrical corporation customers as "benefiting customers" under AB 1613.37 It raises many of the same arguments concerning statutory interpretation as Irrigation Districts. Thus, CCDC maintains the Commission may only include one, two or all three of the customer categories listed in § 2841(e) in the term "benefiting customers."
AReM asserts that costs should only be allocated to bundled customers. It notes that the proposed Standard Contract provides that all benefits under the contract, including all GHG-related rights and benefits, are to be conveyed to the buyer (i.e., electric corporation). As such, AReM asserts that only bundled customers will receive any of the benefits associated with power purchased under AB 1613. 38
AReM also disputes PG&E's conclusion that above-market costs should be allocated to all customers. AReM notes that allocation of "above-market" costs is not included in the statute. It further notes that the name of the statute is not a basis for the cost allocation proposed by the IOUs, since all load serving entities, including electric service providers, are obligated to meet the State's GHG requirements. As such, AReM believes allocation of costs to DA customers would be both anticompetitive and contrary to AB 1613.
Finally, AReM disputes the IOU's proposals that existing Commission decisions concerning cost allocation should be applied to AB 1613. It contends that the allocation methodology adopted in D.06-07-029 is not applicable because the purpose of adopting a broad definition of benefiting customer in that decision was to meet a system reliability need.39 AReM states that AB 1613 does not make any statements concerning a need to improve system reliability, but rather includes a provision in the event procurement under the statute would adversely affect reliability.
AReM concedes that the Commission could impose a non-bypassable charge (NBC) on current bundled customers who later depart utility service and receive electric service from an electric service provider (ESP) or CCA, but contends that the mechanism adopted in D.08-09-012 is not wholly applicable. AReM states that this is because D.08-09-012 does not include the allocation of benefits to these departing customers. Therefore, AReM maintains that if the Commission were to impose an NBC, it would need to conduct a separate proceeding to determine how to calculate and distribute the associated benefits with the departing load.40
Parties' comments raise two main considerations - which customer categories should be included in the term "benefiting customers" and what costs and benefits should be allocated to these benefiting customers. Both of these considerations must be addressed in order to properly allocate costs and benefits to ensure ratepayer indifference.
In determining which customer categories should be included in the term "benefiting customers," we must first consider whether § 2841 expressly limits the term "benefiting customers" to the three customer categories listed in the statute, as has been proposed by some parties. Section 2841(e) states, in pertinent part:
For purposes of this section, "benefiting customers" may, as determined by the commission, include bundled service customers of the electrical corporation, customers of the electrical corporation that receive their service through a direct transaction, as defined in subdivision (c) of Section 331, and customers of an electrical corporation that receive their electric service from a community choice aggregator, as defined in Section 331.1.
A proper reading of this language would indicate that the Commission is to determine which customers are to be included in the term "benefiting customers" and that these groups may include the three categories identified in the statute. However, there is nothing in the statute stating that these are the only customer categories to be included. If the Legislature had intended the list to be inclusive, the statute would have contained more limiting language, such as "may only include" or "shall be limited to." However, it does not. Rather, § 2841(e) states that the term "may, as determined by the Commission, include" the categories listed. This language more reasonably supports a conclusion that the three categories listed in the statute were examples of what categories of customers could be considered "benefiting customers" and not an exhaustive list. As such, our consideration of which customer categories should be considered benefiting customers is not limited to the categories listed in § 2841(e), and may include other categories of customers.
We next consider which customer categories should be allocated the costs and benefits under AB 1613. AReM has argued that benefiting customers should be limited to only those customers that receive the power purchased under AB 1613, since the contract conveys all benefits, such as GHG-related attributes, to the buyer. In contrast, the IOUs have advocated a much broader definition of benefiting customer due to the policy objectives of AB 1613.
We do not agree that only bundled customers would receive benefits under AB 1613. Although the AB 1613 contracts have identified certain quantifiable benefits that shall be conveyed to the buyers, all customers will benefit from reduced GHG emissions, potential reduction in congestion and more efficient utilization of natural gas as a result of encouraging development of these CHP systems. Because all retail end-use customers will receive the beneficial attributes associated with these CHP systems, they would reasonably be considered "benefiting customers" under AB 1613.
This determination is supported by prior Commission decisions. For example, in allocating the costs associated with power purchased by the Department of Water Resources (DWR) between January 17 and February 2, 2000, the Commission determined that all retail end-use customers should bear cost responsibility because these purchases had served to stabilize the entire electric grid during the Energy Crisis.41 Thus, even though not all retail end-use customers received power purchased by DWR during that time period, the overall benefits to all California customers supported a conclusion that costs for that power should be allocated to them. Similarly, all customers will benefit as a result of AB 1613 and, thus, should bear some responsibility for costs associated with these tariffs and contracts. Accordingly, we find that "benefiting customers" shall include all retail end-use customers within the service territory of the electrical corporation.
Although we find that the term "benefiting customer" is not constrained to the categories identified in § 2841(e) and should be construed broadly, we agree with Irrigation Districts that POU customers should not be included in the definition of benefiting customer. As Irrigation Districts note, § 2841.5 requires POUs, such as Irrigation Districts, to establish their own program for purchase of power under AB 1613.
Although AB 1613 provides that the benefits and costs of the electrical corporation's tariff be allocated to all benefiting customers, it does not include a similar provision for a program developed by a POU. Thus, a POU's customers would bear all responsibility for costs under the POU's program, even though all retail end-use customers would receive the intangible benefits associated with this power. We do not believe that the Legislature intended to have POU customers bear a greater responsibility for costs under AB 1613 than other categories of customers when all customers would benefit equally. Accordingly, it would be unfair for a POU customer to be included as a benefiting customer under § 2841(e) since AB 1613 requires the POU to implement its own program. Based on these considerations, we find that "benefiting customers" shall consist of bundled service customers and customers receiving service from either an ESP or a CCA.
The second consideration is what costs should be allocated to the benefiting customers. Generally, all parties state that the above-market portion of stranded contract costs associated with customers departing bundled service may be allocated to these departing customers. We agree that this principle should be followed. However, as we have discussed in Section 3.1 above, the purpose of this FIT is to encourage the development of a certain type of CHP system that provides certain energy efficiency and environmental attributes. Thus, the FIT price may be higher than the average cost of the electrical corporation's procurement portfolio or the cost of energy in the CAISO market.
In this instance, we believe it would be reasonable to allocate the costs associated with the benefits to encourage development of this type of CHP system to all benefiting customers. As discussed in this decision, pricing under the contracts shall include costs associated with GHG attributes, in the form of GHG compliance costs, and an adder for locating within certain load areas. Since these costs would directly be associated with the benefits received by all customers, it would be reasonable to allocate these costs among all customers.
In light of these considerations, we find that the costs associated with the intangible benefits should be allocated to all benefiting customers. This shall be the costs associated with GHG attributes and for locating within certain load areas and will be allocated to benefiting customers on an equal cents/kilowatt-hour (kWh) basis. Calculation of the costs, and allocation among benefiting customers, shall be included in the electrical corporation's annual Energy Resource Recovery Account (ERRA) proceeding.
3.4. Program Cap
AB 1613 provides that "[t]he commission may establish a maximum kilowatt-hours (kWh) limitation on the amount of excess electricity that an electrical corporation is required to purchase if the commission finds that the anticipated excess electricity generated has an adverse effect on long-term resource planning or reliable operation of the grid."42 The Final Staff Proposal recommends that the Commission adopt an interim statewide cap of 500 MW, based on the export capacity of participating CHP, which would be adjusted as part of each IOU's long-term procurement planning process.
The IOUs support the adoption of a program cap. SDG&E/SoCalGas contend that if the AB 1613 program were open-ended, it could be faced with the prospect of having to take power that is not needed.43 Additionally, they present various situations that they believe would justify a limitation on the amount of excess electricity that they should be required to purchase. These include procurement under the state's renewables portfolio standards (RPS) goals and the possible lifting of the suspension of direct access.
SCE contends that AB 1613 establishes a must-take obligation to purchase CHP power, and thus, a kWh limitation is necessary to ensure that there is no adverse effect on long-term resource planning and reliable operation of the grid.44 SCE also points to other state mandates, including energy efficiency and procurement of renewable power, that it believes necessitate establishing a limitation on the amount of power purchased under AB 1613. Therefore, it recommends that the Commission work with the CAISO to determine what this limitation should be. SCE does not oppose Energy Division staff's recommendation for a 500 MW statewide cap, but continues to recommend that the Commission work with the CAISO to establish a program limitation that considers reliability and system effects.45
PG&E also supports establishing an MW cap. It lists a variety of factors that should be considered before an MW cap could be established. Therefore, it recommends that a workshop be held to determine the numeric cap or that the amount be set at 1% of a utility's peak demand.46
Fuel Cell opposes setting any maximum MW limitation. It contends that there is no record to support a finding that purchases under AB 1613 would have an adverse impact on long-term resource planning or reliable operation of the grid.47 It contends that participation in the AB 1613 program will be influenced by pricing and other contract terms and conditions. Thus, it recommends the IOUs should only submit a request for a cap if and when the program results in adverse impacts on planning or reliability. Fuel Cell states that if the Commission does set a cap, it should be considered interim, "with the understanding that the program should be expanded over time to help meet longer-term program capacity goals."48
CCDC similarly opposes establishing any limit at this time. It contends that many of the concerns raised by the IOUs in support of a limit are hypothetical and notes that AB 1613 includes safeguards against the scenarios presented by the IOUs.49 Therefore, CCDC believes that consideration of a kWh limit should not occur until the Commission finds that sale of excess power under the program does in fact have an adverse effect on long-term resource planning and grid reliability. Nonetheless, CCDC states that if an interim cap of 500 MW, allocated proportionally among the electric corporations, is adopted, this cap should be monitored on an on going basis and adjusted before purchases meet that interim cap.50
Pub. Util. Code § 2841(a) allows the Commission to "establish a maximum kilowatt hours limitation on the amount of excess electricity that an electrical corporation is required to purchase if the commission finds that the anticipated excess electricity generated has an adverse effect on long-term resource planning or reliable operation of the grid." Although the IOUs have presented various situations that they believe justify establishing a program limitation, most of them are speculative. We agree with Fuel Cell that participation in the AB 1613 program will be influenced by pricing and other contract terms and conditions. At this point, we find no basis to conclude that the pricing or contract terms adopted in this decision would present an immediate adverse effect on an electrical corporation's long-term resource planning or reliable operation of the grid. Further, any MW limitations should be imposed based on the specific effect of eligible CHP systems on a particular electrical corporation. Accordingly, we decline to adopt staff's recommendation to adopt an interim statewide cap of 500 MW for the AB 1613 program at this time. Should an electrical corporation subsequently find that the number of eligible CHP systems participating in this program has an adverse impact on its long-term resource planning or system reliability, it may file an application seeking authorization to establish a maximum kilowatt hours limitation on the amount of excess electricity it must purchase under this program.
3 Under the Public Utilities Regulatory Policy Act of 1978 (PURPA) and the FERC regulations implementing PURPA, the states have been delegated authority to establish the rates for sale of power by QFs to the utilities at no more than avoided cost.
4 SCE Comments, June 1, 2009, at 8; PG&E Comments, June 1, 2009, at 2-3; SDG&E/SoCalGas Comments, June 1, 2009, at 2-3.
5 The methodology for calculating IOU payments for power purchased from QFs was adopted in Decision (D.) 07-09-040.
6 Indeed, CHP systems participating in this program never would be QFs if they do not apply to the FERC for certification to become a QF. At the time that the FERC adopted rules implementing PURPA, FERC stated that its rules encourage but did not require the development of cogeneration or small power production facilties, and FERC acknowledged that certain cogeneration facilities would be constructed or operated outside of the incentives underlying FERC's QF rules. Small Power Production and Cogeneration Facilities-Environmental Findings (1980) 10 FERC ¶61,314 at 61,633
7 See, e.g., Federal Energy Regulatory Com. v. Mississippi (1982) 456 U.S. 742, 745-46.
8 Small Power Production and Cogeneration Facilities-Environmental Findings, supra, 10 FERC ¶61,314 at 61,632.
9 Pub. Util. Code § 2842.
10 Federal Energy Regulatory Com. v. Mississippi, supra, 456 U.S. at 760.
11 See, e.g., Ameren Energy Marketing Company (2001) 96 FERC ¶ 61,306 at 62,189 & n. 18 (and cases cited therein).
12 Pub. Util. Code § 2840.6, subd. (a).
13 This process and logic can be used to describe either topping-cycle or bottoming-cycle CHP; the policy goal to maximize the use of waste heat applies to both.
14 AB 32 (Stats. 2006, ch. 598) requires, among other things, that the ARB adopt a statewide GHG emissions limit equivalent to the statewide GHG emissions levels in 1990, to be achieved by 2020, in consultation with this Commission and the CEC.
15 See Pub. Util. Code § 2843.
16 The CEC Staff Draft Guidelines may be found at http://energy.ca.gov/2009publications/CEC-200-2009-016/CEC-200-2009-016-SD.PDF.
17 See New York v. FERC (2002) 535 U.S. 1, 20, 23, 24, 28; see also Connecticut Light and Power Co. v. FPC, (1945) 324 U. S. 515, 523-531..
18 See Order No. 888, FERC Stats. & Regs., Regs. Preambles, Jan. 1991-June 1996, ¶ 31,036, p. 31,782 (1996).
19 D.08-03-018, at 81-82 (footnote omitted).
20 See e.g., American Ref-Fuel Co., et al. (2004) 107 FERC ¶ 61,016.
21 In re California Independent System Operator Corporation (Docket ER-06-615) 2007 FERC LEXIS 827, 178.
22 Memorandum on Preemption, published May 22, 2009. DCPD Number: DCPD200900384. This document may be found at http://www.gpo.gov/fdsys/pkg/DCPD-200900384/pdf/DCPD-200900384.pdf.
23 Id.
24 Connecticut Light & Power Company v. Federal Power Commission, 324 U.S. at 525-530.
25 SCE Comments, June 1, 2009, at 8.
26 SDG&E/SoCalGas Comments, June 1, 2009, at 2-3. In contrast, SCE has argued that the currently-adopted methodology for calculating utility avoided cost is not the appropriate measure for ratepayer indifference as it does not believe this methodology results in prices that accurately reflect its true avoided costs. (SCE Comments, June 1, 2009, at 9.)
27 PG&E Comments, June 1, 2009, at 5-6.
28 Fuel Cell Comments, June 1, 2009, at 17.
29 CCDC Comments, June 1, 2009, at 11.
30 These benefits could include environmental benefits due to reduced GHG emissions and more efficient use of waste heat and natural gas, as well as locational benefits associated with reduced congestion in certain load-constrained areas.
31 PG&E Reply Comments, June 15, 2009, at 11.
32 Pub. Util. Code § 2841, subd. (e).
33 SCE Comments, June 1, 2009, at 16.
34 PG&E Comments, June 1, 2009, at 7.
35 Irrigation Districts Comments, June 1, 2009, at 3.
36 Irrigation Districts Comments, June 1, 2009, at 8 (citing D.08-09-012 at 12). In D.08-09-012, "new world generation" was defined as generation from both fossil-fueled and renewable resources contracted for or constructed by the investor-owned utilities subsequent to January 1, 2003.
37 CCDC Comments, June 1, 2009, at 12.
38 AReM Reply Comments, June 15, 2009, at 5.
39 AReM Reply Comments, June 15, 2009, at 5-6.
40 AReM Reply Comments, June 15, 2009, at 8.
41 See D.02-11-074, Attachment A, at 25-26.
42 Pub. Util. Code § 2841(a).
43 SDG&E/SoCalGas Comments, June 1, 2009, at 4; SDG&E/SoCalGas Comments, August 24, 2009, at 9-10.
44 SCE Comments, June 1, 2009, at 10.
45 SCE Comments, August 24, 2009, at 23.
46 PG&E Comments, June 1, 2009, at 8.
47 Fuel Cell Comments, June 1, 2009, at 20.
48 Fuel Cell Comments, August 24, 2009, at 2.
49 CCDC Comments, June 1, 2009, at 14-15; CCDC Comments, August 24, 2009, at 4.
50 CCDC Comments, August 24, 2009, at 5.
