7. Policy Proposals for QFs with Expiring Contracts and New QFs
7.1. Overview
The parties fundamentally disagree on the future role of QFs in the provision of power to the utilities. The QF parties assert that PURPA requirements, as well as California's procurement policies, require that the Commission make available standard offers as a means of implementing PURPA, while the utilities and consumer advocates maintain that the Commission's policy for new QFs and QFs with expiring contracts should be to require such resources to participate in open solicitations with prices to be determined by the outcome of the competitive process.
The IOUs and consumer advocates' long-term policy proposals for QFs are essentially a continuation of the interim approach established by the Commission in D.04-01-050 with the exception of the elimination of the five-year Revised Standard Offer 1 (RSO1) contract availability approved in D.04-01-050, and D.05-12-009. The IOUs propose three ways for QFs to obtain new power purchase agreements (PPAs). The first is participation in one of the utilities' all-source or renewable competitive solicitations. The second is bilateral contract negotiations. For both of these options, the pricing and terms would be set by the final negotiated PPA. The third option is a one-year market-based standard offer. Each utility's one-year market-based proposal is slightly different, but essentially, the QFs would have access to a one-year market-based standard offer as long as the PURPA mandatory purchase obligation remains in effect. The IOUs believe that these three options comply with PURPA, meet the Commission's EAP II loading order preferences, and are consistent with the Commission decisions D.04-01-050, and D.04-12-048. TURN and DRA support the IOUs' recommendations.
The IOU and consumer advocates also argue that QF contracts should include all up-to-date terms and reflect current electricity procurement requirements, including integration of QF resources into the CAISO tariffs. They note that this recommendation is consistent with the policy enunciated in the EAP II, specifically, Key Action Item 7 of Section 4, which states "adopt a long-term policy for existing and new qualifying facility resources, including better integration of these resources into CAISO tariffs and deliverability standards." These parties maintain that any future power purchase contracts should be consistent with CAISO tariffs, rules, regulations and protocols and utilities should not have to act as scheduling coordinators for QF power purchase contracts. The CAISO agrees.
The QF parties strenuously object to the IOUs' proposals. The QF parties believe that absent a Commission order to contract with cogeneration QFs on a "must-take" basis, the utilities could essentially eliminate these resources from their portfolios. The QF parties argue that despite repeated urging from the Commission in D.03-12-062 and D.04-01-050, and several rounds of utility power solicitations, QFs have not be able to compete successfully in the solicitations. The QF parties maintain that QFs have been unsuccessful because the terms of the utility solicitations, including requiring new facilities, dispatchable facilities, or certain minimum size restrictions, are not compatible with certain existing QF operations.
The QF Parties recommend that the Commission should provide the following options to QFs with expiring contracts and new QFs: (1) A QF could choose to be paid SRAC and as-available capacity payments (similar to the existing SO1 contracts); (2) If the QF is willing to enter into a PPA of at least 10 years but no more than 20 years, the QF should receive a PPA based on the all-in cost of a new combined cycle power plant, using updated assumptions and the Commission's MPR pricing model; and (3) negotiated agreements. CAC/EPUC and CCC also recommend that the Commission adopt, as a goal, a cogeneration portfolio standard. The cogeneration portfolio standard would require the utilities to continue to make available long-term standard offer contracts until they achieve a 25% increase in the amount of cogeneration in California over and above January 1, 2005 levels by the end of 2010.
7.2. Parties' Positions
PG&E proposes that the Commission require QFs to compete in utility resource solicitations on an equal basis with other resources. PG&E contends that the record and the relevant law establish that the results of competitive solicitations would more closely reflect the utilities' avoided costs than an estimate of the cost of a CT. PG&E notes that each of the QF proposals for an administratively-determined long-run avoided cost (LRAC) price contains different values for long-term energy, capacity, and O&M, thereby demonstrating that any estimate selected by the Commission is highly likely to be incorrect. Moreover, PG&E maintains that each of the proposals is too high because they do not reflect the dispatchability benefit inherent in a CT that is not present in a QF contract.
PG&E also argues that the QF parties' proposals violate PURPA in that they do not reflect the many types of facilities available to sell power to the utilities, as required by FERC. PG&E notes that the proposed prices are higher than the prices paid for renewable power in recent RPS solicitations. PG&E states that it has conducted twelve solicitations since it resumed procurement in 2003 and argues that if QFs have not been successful in these solicitations, it is because they have elected not to compete due to the option of a higher-priced SO1 contract.
PG&E proposes that QFs with existing contracts may sell energy to PG&E at market-based prices under a one-year contract based on the Edison Electric Institute (EEI) Master Agreement. PG&E states that the EEI Master Agreement is widely recognized in the industry and has been approved by the Commission for use in the RPS program. PG&E argues that using the EEI Master Agreement for QF power purchases going forward would make QF contracts consistent with those of other wholesale providers and would eliminate the contract provision advantages QFs currently have over their non-QF competitors. Specific contract modifications proposed by PG&E are listed in Table 4-3 of Exhibit 28.
PG&E emphasizes that the Commission should not adopt the QF proposals to allow QFs capable of committing to the delivery of firm capacity the option to sign as-available SO1 contracts. PG&E also maintains that federal policy favors moving QFs to wholesale competition, citing the August 8, 2005, Energy Policy Act of 2005.
Finally, PG&E argues that if any of the QF proposals are adopted, there will be a rush for the new contracts because the proposed prices are above market rates and the contract terms impose virtually no performance obligations outside of the three summer months.
SCE states that the Commission should adopt policies that support cost-effective cogeneration that benefits retail electricity customers. In particular, SCE emphasizes that the Commission must adopt long-term QF policies that are consistent with the other resource planning decisions adopted by the Commission as well as PURPA requirements. According to SCE, mandating a priority position for QFs and requiring that the utilities make available long-term standard offers to all existing cogenerators upon expiration of their current contracts does nothing to support cost-effective cogeneration. Instead, such a policy will support inefficient cogeneration.
SCE objects to the QF parties' proposal to determine LRAC pricing based on a Combined Cycle Gas Turbine (CCGT) proxy. SCE believes that "only if a QF were willing and able to operate in a dispatchable manner, so that the utility could curtail its output when less expensive baseload energy is available, would it be appropriate to use a CCGT proxy." (Exhibit 2, p. 78.) SCE also points out that although certain QF parties have attempted to use SCE's Mountainview contract to justify CCGT proxy prices, the Mountainview contract contains many beneficial features that QF contracts do not, including a provision for the Mountainview project to be transferred to SCE at the end of the 30-year agreement term.
SCE recommends that the Commission require QFs to participate in utility resource solicitations, and if they choose not to, or are unsuccessful, provide a one-year market-based contract that would remain available as long as the PURPA mandatory purchase obligation is in effect.
SDG&E generally agrees with PG&E and SCE and recommends that the Commission require new QFs and QFs with expiring contracts to participate in utility solicitations. SDG&E also recommends that for existing QF contracts, a multi-year (one-to-five year) fixed price energy option, mutually agreed to via bilateral negotiations, should be permitted as discussed below. The pricing terms would be for one to five years and would be arranged by mutual agreement based on border gas forward prices and SRAC energy price transition formula as determined in this proceeding. PG&E and SCE are not opposed to a five-year fixed contract as long as the contract is voluntary on the part of the utility.
TURN states that the QF industry has embarked on an aggressive public relations campaign, in which they assert that the very existence of QF power in California is at risk if the Commission fails to accede to their pricing and contracting demands. TURN maintains that the Commission must recognize this campaign as an attempt to blackmail policymakers into authorizing another generation of above-market long-term QF contracts.
TURN would also support making five- to ten-year contracts available for certain existing QFs with expiring contracts and certain new QFs as long as those contracts were based on market prices. TURN states that it supports the IOUs' approach if SRAC pricing is not reformed as TURN recommends. However, if the Commission adopts the TURN reforms for SRAC pricing, TURN could support making five- to ten-year contracts available for QFs with expiring contracts and certain new QFs who might otherwise find it difficult to participate in the wholesale market and/or in utility solicitations.
CAC/EPUC believes that the proposals presented by the utilities and the CAISO are contrary to the state's stated preference for cogeneration and do nothing to either preserve existing resources or to encourage new resources to be built. CAC/EPUC claims that cogeneration provides substantial benefits to the state, including (1) reduction in natural gas consumption, (2) reduction in emissions, (3) increased thermal efficiency, (4) capacity located within California, (5) increased electric system reliability, and (6) reduced impacts on the transmission grid.
CAC/EPUC describes cogeneration as the "sequential production of both useful thermal energy (such as heat or steam) used for industrial, commercial, heating or cooling purposes, and electric energy, from a single source of fuel." They jointly argue that the unique dual use of that fuel results in a reduction in the overall consumption of that fuel thereby providing both energy efficiency and environmental benefits. For cogenerators that produce more electrical energy than is consumed on site, the option to employ cogeneration technology is tied to the ability to harmonize the operation of the cogeneration facility with the production requirements of the thermal host and the electrical needs of the utility. CAC/EPUC also note that the types of companies which rely on thermal energy output of a cogeneration facility for their core operations will only continue to operate under a cogeneration configuration for as long a such a configuration continues to be economic, provides a reasonable certainty of operational longevity and does not jeopardize their ability to produce their core business product. (CAC/EPUC Opening Brief, pp. 36-37.) CAC/EPUC states that cogeneration resources are not and never will be fully dispatchable merchant facilities, since they are designed to serve thermal energy load and the right to dispatch or curtail would adversely impact the industrial obligations. CAC/EPUC asserts that because of cogeneration's unique operating characteristic (i.e., the need to harmonize both the electrical and thermal output) the only viable purchaser of electric power from a cogeneration facility is the utility. This is because of the utility's inherent long-term baseload requirements and the relatively large resource portfolio that allows cogeneration to be operated in a baseload mode consistent with cogeneration thermal output requirements.
CAC/EPUC argues that absent a long-term commitment, the continued operation of existing cogeneration facilities and the electrical energy supplied by these projects would be jeopardized. CAC/EPUC emphasizes the importance of state law, as set forth in Pub. Util. Code § 372, in encouraging the Commission to support the continued development, installation, and interconnection of clean and efficient self-generation and cogeneration resources, and to improve system reliability for consumers by retaining existing generation and encouraging new generation to connect to the electric grid.
CAC/EPUC also cites the EAP II:
In furtherance of this important goal, EAP II sets forth the following key actions related to the preservation of existing CHP resources and the encouragement of new resources: (1) provide for the continued operation of existing generation need to meet current reliability needs, including combined heat and power generation; (2) adopt a long-term policy for existing and new qualifying facility resources, including better integration of these resources into CAISO tariffs; and (3) encourage development of environmentally sound distributed generation projects, including combined heat and power resources.
CAC/EPUC argues that the CEC has also recognized cogeneration as a critical loading order resource through its 2005 Integrated Energy Policy Report (IEPR) process, stating "cogeneration, combined heat and power" (CHP) is the most efficient and cost-effective form of DG [distributed generation], providing numerous benefits to California including reduced energy costs; more efficient fuel use; fewer environmental impacts; improved reliability and power quality; locations near load centers; and support of utility transmission and distribution systems. (2005 IEPR at p. 74.)
CAC/EPUC also point out that the Commission has expressed its support for the preservation of existing QFs in D.04-01-050, finding that "QF power provides numerous benefits to California, including environmental attributes, local power production, and economic development" (D.04-01-050, Finding of Fact (FOF) 71) and that "It is in the State's interest for QFs to continue to provide those benefits over the long term, especially when they are already in existence." (Id., p. 151.)
CAC/EPUC believes that long-term contract price should be based on the actual LRAC from utility specific resource plans, e.g., the specific cost of resources in these plans should be the costs paid to QFs. They explain that since they did not have access to this level of cost information from the utilities' resource plans, an alternative surrogate resource, or combined cycle generating turbine, or CCGT, should be used as a proxy for the utilities' long-run avoided costs. CAC/EPUC maintains that the most reasonable LRAC pricing proxy is the CCGT proxy approved for the RPS. They argue that the MPR model can be readily employed to perform the necessary calculation based on recent long-term baseload resource proposals of the utilities. For an illustrative 20-year agreement beginning in 2008, the LRAC energy and capacity would be as follows, with the gas price input for each utility the same as that used for calculating their SRAC:
Capacity Payment ($/kW-Year) = $142
Variable O&M ($/MWh) = $2
Heat Rate (BTU/kWh) = 7,500
Capacity Factor = 92%.
CAC/EPUC argues that the IOUs' one-year as-available contract is unacceptable, but, given the problematic nature of participation in the utility resource solicitations, this option may be the only option that is executable. However, without a long-term contract, there is no guarantee that an industrial customer will have an outlet for the electrical energy that is produced in the cogeneration process. The one-year contract is also in conflict with the IEPR, according to CAC/EPUC, because a one-year contract at market-based prices is contrary to the IEPR's desire for the utilities to engage in long-term commitment to cogeneration. CAC/EPUC also claims a one-year contract violates PURPA because it is offered at prices which have not been demonstrated to reflect avoided cost.
CAC/EPUC also opposes the CAISO proposal to require QFs executing new contracts to comply with CAISO tariff requirements. According to CAC/EPUC, the CAISO's proposal would reduce California's ability to implement EAP II and IEPR cogeneration objectives, by subjecting cogeneration operation to federal jurisdiction and because it lacks any priority for cogeneration. CAC/EPUC cites Pub. Util. Code § 372 (f) in support of its position that California should not accede to this request. Section 372(f) states, in part, "If the commission and EOB [Electricity Oversight Board] find that any policy or action of the CAISO unreasonably discourages the connection of existing self-generation or cogeneration or new self-generation or cogeneration to the grid, the commission and the Electricity Oversight Board (EOB) shall undertake all necessary efforts to revise, mitigate, or eliminate that policy or action."
EPUC/CAC support TURN's position on new QFs under 25 MW that consume at least 25% of their power internally. However, EPUC/CUC recommend modifications to the TURN proposal to state the limit as an annual GWh limitation rather than a capacity limitation.
DRA recommends that new long-term contracts for QFs be obtained by either participation in the IOU's general and renewable resource solicitations or by negotiating bilateral contracts with IOUs. As a backstop, DRA recommends that a one-year contract similar to SO1 be available for QFs who do not obtain contracts through other means.
DRA also recommends that the Commission adopt the standard terms and conditions of EEI model contracts, such as the EEI Master Agreement, in any future QF contracts authorized under this order. (Exhibit 154, p. 29.) DRA states that such contract standardization would promote: (1) full competition between QFs and non-QFs (2) provide the IOUs with an "apples-to-apples" comparison of competing resources, and (3) provide a closer fit between IOU portfolio need and contracted projects.
The IEP recommends that existing QFs should have the right to obtain a long-term contract based on the IOUs' long-run avoided costs. IEP states that the QFs should receive three payments: (1) a fixed capacity payment based on the levelized value of the fixed costs associated with a long-run avoided resource; (2) a fuel payment equal to the heat rate associated with the avoided resource multiplied by the cost of fuel; and (3) a variable O&M payment based on the variable O&M associated with the avoided resources multiplied by the QF's generation. IEP recommends using the 2004 MPR model and input assumptions to calculate the levelized fixed capacity payment, updated to reflect recent values for costs of construction, financing, and operation of new combined cycle facilities.
IEP argues that the adopted capital costs in the 2004 MPR did not include the cost of transmission interconnection, project laterals, environmental mitigation, emissions offsets, and cooling equipments, and is therefore too low. IEP recommends that the capital costs be updated to equal the mean value of the capital costs for Mountainview, Palomar, and Contra Costa 8. However, IEP recommends adjusting the capital costs for Mountainview and Contra Costa 8 to reflect the fact that these plants were acquired after a distressed sale and partial development, respectively. IEP recommends the average of the $740, $1,017, and $850 capital costs for Mountainview, Palomar and Contra Costa 8, or $869/kWh.
IEP also states that the assumed capacity factor for the current MPR's combined cycle is too high. IEP believes that the capacity factor for determining LRAC should be lowered to reflect periods when it is uneconomic to operate the plant. IEP believes that a reasonable value is an 80% capacity factor. IEP also states that the heat rate for the combined cycle is too low, and an appropriate heat rate is 7,400 Btu/kWh reflecting a new heat rate of 6,950, a heat rate degradation factor of 3.5% and a 200 Btu/kWh increase in heat rate due to dry cooling. IEP's recommendations result in a fixed capacity payment of $129/kW-year, a heat rate of 7,400, and a variable O&M payment of $2.50/MWh.
IEP states that new QFs should have to participate in the utilities' solicitation process, to prevent over-subscription of the standard offers.
CCC recommends that the Commission approve a long-term firm capacity contract for QFs, and specify the minimum terms and conditions that such contracts must contain. Existing QFs should have the option to sign the new long-term firm capacity contract once their original contracts expire. Alternatively, CCC believes that QFs should have the option to extend their original firm capacity contracts on the same terms and conditions as specified therein, but subject to the contract lengths and LRAC prices that are approved for the new contract.
CCC also recommends that the Commission should continue to offer an as-available contract option priced at SRAC energy and as-delivered capacity prices with the same terms and conditions as the existing SO1, including the termination provisions, which give the QFs the ability to terminate the contract upon 30 days' notice to the utility. CCC states that this 30-day termination right is consistent with the as-available nature of the SO1 contract (i.e., the QF is under no obligation to deliver energy).102 CCC believes that the as-available pricing option should be available to QFs for a contract term of up to 15 years.
CCC emphasizes that the approval of minimum contract terms and conditions is essential to ensure that QF contracts can be developed on a timely basis, without the need for negotiations between the utilities and QFs. CCC recommends the following terms and conditions:
Term - The contract should be available for terms of 10, 20, or 25 years, to be selected by the QF.
Purchase Obligation - The utility would be obligated to purchase, and the QF would be obligated to deliver, firm capacity at a level that is selected by the QF and specified in the contract (Contract Capacity). The utility would also be obligated to purchase any capacity made available in excess of the Contract Capacity ("As-Available Capacity"). The utility would be obligated to purchase all energy made available by the QF, which would be measured as either (1) the QF's gross output in kilowatt hours, less station use and transformation and transmission losses to the point of delivery (i.e., the QFs net energy output) or (2) the QF's gross output in kilowatt hours less station use, any other use by the QF (such as the sale of power to its onsite host facility) and transformation and transmission losses to the point of delivery (i.e., the QF's surplus energy output). The QF would be entitled to specify how energy is sold.
Creditworthiness - The contract should not require the QF to post collateral or provide any form of credit support.
Performance Standard - The QF would be entitled to receive, and the utility would be obligated to pay, the full firm capacity payment specified in the contract as long as the QF delivers the Contract Capacity during the peak hours of the peak months as defined in the contract ("Peak Period"), subject to a 20 percent allowance for forced outages at the QF. In other words, the QF would be entitled to the full firm capacity payment as long as the QF delivers 80 percent of the Contract Capacity during the Peak Period. This performance standard is the same one that appears in existing firm standard offer contracts.
Bonus Capacity Payments - The QF would be entitled to receive, and the utility would be obligated to pay, increased capacity payments when the QF exceeds the performance standard required for payment of the full firm capacity payment.
Scheduling Requirements - The utility should continue to be the scheduling coordinator for QF generation supplied under the contract, unless the QF chooses to schedule its own power.
Curtailment - The utility would be entitled to refuse deliveries from the QF only (1) when reasonably necessary to conduct repairs on its system, (2) when reasonably necessary because of emergencies or forced outages on its system, or (3) during other periods when FERC's regulation implementing PURPA allow the utilities to curtail QF deliveries.
Dedication of the Facility - The QFs output would be deemed to be dedicated to the utility up to the amount of Contract Capacity. The QF would retain the right and ability to use or sell elsewhere any and all capacity and energy generated in excess of the Contract Capacity.
Interconnection - For QFs supplying power under an existing utility contract that has expired, or that is set to expire, the contract should provide for an extension of the existing interconnection arrangements that is commensurate with the term of the new contract.
CCC states that the LRAC prices for energy and capacity should be based on an all-in CCGT proxy similar to that used to develop the MPR. However, CCC notes that "one can find CCGT cost estimates that span a wide range," and "[F]or the purpose of setting LRAC prices for QFs, the Commission should use CCGT cost data that meets a higher standard than the CCGT data that has been used for other purposes."103
CCC recommends that the Commission consider SCE's Mountainview project and SDG&E's Palomar project as potential CCGT proxies. However, for Mountainview, CCC notes that the capital costs should be adjusted upwards by at least 11% to reflect the discount that SCE received for this distressed project. CCC argues that the EAP II identifies CHP as a preferred loading order resource and establishes the continued operation of existing cogeneration resources and new cogeneration resources. CCC argues that new long-term contracts are essential if California is to retain existing generation resources, to encourage existing cogenerators to invest new capital to improve their resources and to attract new cogenerators.
The Renewables Coalition recommends that the Commission adopt both a long-term firm capacity contract and a long-term as-available capacity contract for QFs whose contracts expire and for new QFs. According to the Renewables Coalition, the firm capacity contract should be available to existing QFs upon expiration of their existing contracts and to new renewable QFs in each utility's service territory until the utility has met its RPS program goals.
The Renewables Coalition also recommends that the Commission should adopt an as-available capacity contract based upon the current SO1 contract for renewable QFs. The Renewables Coalition states that the contract should contain as-available capacity and SRAC energy prices, should be available for up to at least 15 years, and should be terminable by the QF upon 30 days' prior notice by the QF. The Renewables Coalition recommends that the Commission adopt the terms proposed by the CCC.
The Renewables Coalition argues that each of their proposals is supported by the record, as well as by existing law and policy favoring the increased procurement of renewable power. Specifically, the Renewables Coalition maintains that its long-term QF procurement policy will support the Commission's RPS goals and is in fact necessary as a backstop to the RPS program to ensure that the benefits of existing renewables are fully captured by California ratepayers. The Renewables Coalition states that the RPS solicitations themselves do not ensure that renewable QFs will have purchasers for their power upon expiration of their existing contracts. They note that the utilities are only required to meet their annual procurement targets through solicitations if there are adequate Public Goods Charge funds available to support payments in excess of the MPR. They also note that the utilities are not obligated to procure from renewables in excess of the 20% goal established by the RPS program.
The Renewables Coalition also argues that the RPS program is structured such that existing renewables risk exclusion. Existing renewables are not eligible to obtain Supplemental Energy Payments (SEPs) as part of the RPS program. Small renewable QFs are prohibited from bidding in RPS solicitation because they cannot offer a product that is one MW or greater in size and/or cannot comply with certain terms and condition in the RPS solicitations such as credit guarantees. The Renewable Coalition states that existing biomass facilities are unable to compete with more modern wind or geothermal facilities, therefore the RPS program is not likely to be viable option for these less cost-effective renewables. The Renewables Coalition argues that by adopting long-term LRAC contracts as a complement to the RPS program solicitations, the Commission will ensure that all renewable resources, both existing and new, are encouraged.
7.3. PURPA Purchase Obligation
Before addressing the merits of the parties' long-term recommendations, we believe it is useful to discuss our PURPA obligations. The Commission has found it necessary to adjust its implementation of PURPA periodically over the years. Prior to electric restructuring, Standard Offer contracts allowed QFs to unilaterally choose a contract term of up to 30 years, and some Small QFs obtained evergreen contracts which may only be terminated by the QF. SO2, SO3, and ISO4 offers were also available, some with fixed energy prices and/or fixed capacity prices for terms of up to 30 years.104 Over the years, the Commission eventually suspended the availability of virtually all of the standard offers, first due to oversubscription and inaccurate pricing, and then due to electric restructuring. The bulk of the remaining QF contracts are now due to expire over the next decade.
In several recent procurement orders, we have articulated our interpretation of PURPA requirements. In D.02-08-071, we noted that PURPA gives us considerable discretion in its implementation and does not obligate us to continue standard offer contracts.105 At that time, no new SO1 contracts were available and we offered a limited extension of certain contracts to ensure reliability of supply as the utilities resumed procurement following the electricity crisis. We next considered this issue in D.03-12-062, again offering a limited extension of certain expiring QF contracts. However, in D.03-12-062 we also noted that while "QF participation in such solicitations is the best way for the IOUs to match their need for new capacity with the range of potentially available resources, including QFs... we do not believe that such participation should be mandatory for existing QFs seeking to renew their contracts." (D.03-12-062, p. 5.)
In D.04-01-050 we addressed our PURPA obligations as we considered whether to grant further extensions of SO1 or offer contracts to new QFs. In that case, we found that FERC's Ketchikan order and Order No. 69, provide more specific guidance on this question of whether we are obligated to offer contracts to new QFs as follows:
...we find that compliance with the utility purchase obligation, by means of a purchase that would displace power from the Four Dam Pool Initial Project, is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA. We make this finding because, as we have stated previously, there is no obligation under PURPA for a utility to pay for capacity that would displace its existing capacity arrangements. Moreover, there is no obligation under PURPA for a utility to enter contracts to make purchases which would result in rates which are not `just and reasonable to electric consumers of the electric utility and in the public interest' or which exceed `the incremental cost to the electric utility of alternative electric energy.' 16 U.S.C. § 824a-3(b) (1994). (Footnotes omitted, emphasis added) City of Ketchikan (2001) 94 FERC 61,293, pages 15-16.
Thus, as FERC itself has recognized, we must balance the PURPA mandate that utilities are to purchase energy and capacity from QFs with the overarching requirement that electric utilities may only charge just and reasonable rates for the power they supply to their customers. In this order, we continue to find that PURPA does not require us to create new standard offers that do not reflect the utilities' resource needs or market conditions.
Proponents of long-run standard offers argue that standard offers are the best, if not the only effective mechanism to encourage QF generation in the state. In their view, the unique operational characteristics of cogeneration resources, combined with IOU reluctance to sign contracts with QFs, will force QFs with expiring contracts off-line. They argue that a standard offer approach is the only way to effectively comply with the EAP II directives to encourage cogeneration. These parties maintain that the benefits of QFs overshadow and outweigh the potential concerns regarding high prices of excessive supply associated with prior standard offers. They calculate benefits of QFs such as gas savings, locational benefits, reduced emissions, and job creation, that are not quantified or included in avoided cost but that should be considered by the Commission. They also argue that they should continue to be treated as must-take generation and should not be subject to CAISO tariff requirements.
We have a strong policy, expressed in the EAP II, to encourage distributed generation projects. Nothing in this Decision is intended to signal a departure from, or a weakening of, our commitment to clean DG. However, this proceeding is not the appropriate forum to define a broader DG policy and it is not necessary to reach a conclusion on the exact meaning of CHP in the EAP II.
We are troubled by the QFs' assertions that there are significant barriers to entry in IOU power solicitations. The QF Parties are concerned that solicitations may shut them out of future procurement opportunities because the utilities have each indicated in one form or another that they prefer dispatchable resources to baseload, or that they have no need for additional as-available capacity. The QFs complain that, to date, IOU solicitations have imposed conditions on bidders that are unworkable for most cogeneration QFs. Furthermore, the QFs assert that the IOUs have emphasized that for the foreseeable future, they are only willing to purchase firm, dispatchable resources, even if this limitation would eliminate most cogeneration projects from the range of potential suppliers. The QFs also note that for many QFs, their only option is to sell to the utilities.
As we previously stated:
To the greatest extent possible, the utilities should conduct power solicitations for the specific power products needed to meet their load-serving obligations. The utilities should avoid the exercise of monopsony power through arbitrary segmentations of potential bidders. The utilities should spend much more time signaling their power product needs to the market so as to encourage all qualified bidders to participate.
While we did not give any specific instructions in D.04-12-048 to the IOUs for including or excluding bidders from RFOs, we encourage the IOUs to be as inclusive as possible in their RFOs. We will refine the directives for RFOs, as needed, in the 2006 LTPP decision. (D.05-12-022, mimeo., pp. 16-17.)
This point was reiterated when we issued our Rulemaking to Promote Policy and Program Coordination and Integration in Electric Utility Resource Planning, R.06-02-013 (see R.06-02-013, p. 11) and we stress these points here. Based on all of these considerations, we provide the following three options for QFs in the next section of this decision.
7.4. Prospective QF Program
The Prospective QF Program contract options are available to QFs with existing contracts, as well as QFs that are, or were, on contract extensions set forth in D.02-08-071, D.03-12-062, D.04-01-050, and D.05-12-009. The Prospective QF program is also open to new QFs, i.e. facilities that are not in existence as of today's decision.
First, for existing QFs, the utilities shall offer new one- to five-year, as-available standard offer contracts to QFs. The contracts shall be updated to require compliance with CAISO tariffs, including the Resource Adequacy (RA) tariff. However, QFs with expiring contracts seeking to sign new, one- to five-year as-available contract shall not be required to provide new credit support provisions nor new interconnection studies.
QFs under the one- to five-year as-available contracts shall receive SRAC energy payments as discussed herein along with the as-available capacity payment described herein. As described above, six months after MRTU is fully operational, we anticipate further adjustments to the revised MIF will go into effect. The prices paid under all one-to-five-year contracts entered into pursuant to this Decision will be adjusted on a going forward basis using the revised MIF. New contracts will be subject to any changes in capacity payments resulting from future modifications to the RA counting rules; existing contracts will not be affected. QFs larger than one megawatt in dependable capacity will be responsible for scheduling coordination with the CAISO. However, at the election of the QFs, the utilities must provide that service for a reasonable cost. We adopt PG&E's recommendation to use the EEI Master Contract as a starting point for new QF contracts, as described herein.
Second, the utilities will offer a one- to ten-year contract term to those QFs with expiring contracts that are willing to provide unit firm capacity and that desire a longer-term contract. As with the as-available contracts, QFs under the one- to ten-year fixed capacity contracts will receive energy payments based on the MIF, as discussed herein, with the prices paid under all one- to ten-year contracts adjusted on a going forward basis to reflect updates to the MIF. Long-term firm capacity payments will be based on the MPR model in Resolution E-4049 and using a 10 year contract term, less the value of savings gained from inframarginal rents, which results in a cost of $91.97/kW-year. The higher capacity payments associated with the firm capacity contracts will appropriately compensate the QFs for the increased hedge value of assuring firm capacity for a longer term. These contracts will only be available to those QFs willing to offer unit-firm capacity. The all-in payments associated with the two prospective QF Program options are shown in Table 4a, attached to this order, at an illustrative gas price.
Third, we adopt contract provisions for "small" QFs under 20 MW as described by TURN and modified by EPUC/CAC. As stated by TURN and EPUC/CAC this option is necessary because a small QF is unable to bid in a utility RFO, generally does not have the resources or expertise required to negotiate and enter into a bilateral contract with a utility, and is prohibited by current rules from selling surplus generation directly to the CAISO. This option will further the goal of EAP II to encourage the development of new DG.
TURN and CAC/EPUC recommended a size limitation of 25 MW. However, for purposes of this decision, in order to maintain consistency with the FERC definition of small QFs, we define small QFs as QFs under 20 MW. This limit is defined as QF that are 20 MW or less, or that offer equivalent annual energy deliveries of 131,400 MWh, and that consume at least 25% of the power internally and sell 100% of the surplus to the utilities. This definition includes any new increments of capacity added to the project. These new QFs shall interconnect to the utility under Rule 21.
Any new QF contracts will also have updated performance requirements to reflect the firm capacity, but QFs with expiring contracts seeking to sign new unit-firm contracts shall not have to provide additional credit support, nor should they be required to perform additional interconnection studies. QFs larger than one megawatt are responsible for scheduling coordination, although the utilities must offer scheduling service to QFs at a reasonable cost. QFs who are not able to offer unit firm capacity will be able to either continue on a one- to five-year as-available contract from year to year or may participate in utility resource solicitations and bilateral negotiations.
Finally, nothing in this Decision bars QFs desiring longer-term contracts or more flexible contract options, from participating in utility resource solicitations or bilateral negotiations. We do not expect or desire all QFs to continue on SRAC-based pricing. The prices paid to winning bidders in competitive solicitations can best reflect the utility's long-run avoided cost for the specific type of product needed and provided. As we stated in D.96-10-036, "[N]o preference for QF power justifies payment above levels arrived at by all source bidding, as such above market prices would violate PURPA's standard of ratepayer indifference."106 We uphold the same principle today. Contrary to the QF representatives claims, we are under no PURPA obligation to require long-term standard offers, and we find no mandated minimum term for PURPA required purchases. Looking to FERC regulations, we similarly find no mandated minimum term.107 We do not want to see erosion of the utilities' QF supplies, therefore we expect that as old QF contracts expire, new or renewed QF contracts will replace them.
However, if a QF over 20 MW seeks access to one of the contract options described above, the IOU must determine if it would be inconsistent with the existing need determination from the Long-Term Procurement Plan (LTPP) proceeding. Further, the utility must consult with its Procurement Review Group (PRG) within 20 days of receiving a contract request from a QF. The PRG consultation period shall be initiated within 20 days of receiving a contract offer from a QF. If a QF believes that a contract is being unreasonably withheld, it may file a complaint with the Commission. Utilities and QFs will also have the opportunity to address the need for new contracts as part of the utilities' long-term procurement plan filings in R.06-02-013 or its successor.
As discussed above, IOUs may not deny either of the 2 contract options above to small QFs under 20 MW on the basis of over-subscription. However, in order to provide certainty to the IOUs we cap the total amount of QF power under the small QF option to 110% of each IOU's QF capacity as reflected in Table 5. The total amount of QF capacity under contract for PG&E is 2,166 MW, SCE is 4,162 MW, and SDG&E is 270 MW. Therefore, the IOUs cannot reject a small QF request for a contract due to oversubscription unless that contract would cause the IOU to have more than a 10% growth in its overall QF portfolio as reflected in Table 5 to this Decision. We will reevaluate the size of this cap in the long-term procurement proceeding.
As stated by TURN and EPUC/CAC this option is necessary because a small QF is unable to bid in a utility RFO, generally does not have the resources or expertise required to negotiate and enter into a bilateral contract with a utility, and is prohibited by current rules from selling surplus generation directly to the CAISO. The cogenerators point to the fact that the QFs have not obtained contracts with utilities through competitive solicitations as evidence that they will not be successful if required to compete against non-QF generators. (CCC Opening Brief, pp. 63-64.) On the other hand, the utilities argue that the QFs have chosen not to participate in these solicitations because SO1 PPAs have been available as a result of Commission direction in D.02-08-071, D.03-12-062, D.04-01-050 (five-year), and D.05-12-009 and the QFs have not been required to participate. We have a chicken and egg problem. Utilities state that the prices paid for energy and as-delivered capacity under the SO1 agreements averaged $87.44 in 2005 and exceed the spot market prices for firm energy and capacity, even though they have no performance requirements.
Despite the utilities' assertions that their RFOs are open to QFs, it is clear that more needs to be done to ensure that QFs are able to compete. For example, PG&E witness La Flash testified that baseload QFs were able to bid a baseload product in PG&E's 2004 solicitation even though PG&E needed only dispatchable and shaping resources. (RT 3444.) In this case, while the RFO is "open" to baseload QFs, it may not be useful to submit a bid. Clearly, then, if we are to encourage QFs to remain on line but be active in RFOs, the RFOs need to be more open to QFs. As QF contracts, expire, utilities should be soliciting new QFs, especially those in local load pockets. For example, with the advent of local RA requirements in D.06-06-064, we expect the IOUs to seek to retain existing local RA generation that counts towards local RA requirements.
FERC has approved the use of solicitations for complying with PURPA. As SCE points out, FERC determined that a QF that unsuccessfully bid to supply capacity and energy to a utility had its complaint dismissed by FERC, with FERC holding that PURPA did not obligate the utility to purchase from the QF. In that decision, FERC stated:
[a]voided costs are determined, in the first instance, by all alternatives available to the purchasing utility. Those alternatives, as we have explained in a number of recent orders, include all supply alternatives. Here the [utility's] supply alternatives included the power sale agreement offered by the [winning bidder]. If the QF... could not match the rate offered by a competing supplier of power to the [utility], regardless of whether the competitor was or was not a QF, then the QF demonstrably was not offering a rate at the [utility's] avoided cost - and the [utility] had no obligation under PURPA to purchase power offered at a higher price than the lowest bid.108
In conclusion, we find that a combination of market-based offers along with the ability to compete for longer-term contracts best reflects the utilities' avoided cost and meets California's goals for acquiring and retaining cost-effective, environmentally sound generation. First, it provides both short and longer-term options for market-based contracts. Second, for each procurement cycle, the IOU must propose a portfolio of resources that reflects the continuation of QF capacity. The IOU must demonstrate that their solicitations encourage the participation of QFs whose contracts are expiring.
In recognition of the often lengthly process involved in negotiating contract terms, we will adopt CAC/EPUC's recommendation for existing firm capacity QF resources whose contracts expire before the contracts required by this decision are available. The QF may extend the non-price terms and conditions of the expiring contract and continue service with the pricing set forth in this Decision until the final contract is availiable.
Furthermore, requiring the utilities to make available one to ten-year unit firm capacity contracts, as well as optional one- to five-year as-available contracts is consistent with and supports one of the key actions in the EAP II. Our prospective QF Program process will ensure that the amount of QF power under contract is consistent with the utilities' need. If a utility currently does not need additional QF power, for example, the utility is only required to renew existing contracts if it chooses, and will not be required to purchase new QF capacity if the utility can demonstrate that it no longer needs capacity. The processes and the Small QF cap that we adopt today achieves a reasonable balance between the utilities' procurement needs and a viable market for QFs.
As noted above, the Commission has stated its intent to encourage cogeneration and DG, however we cannot do so in manner that results in payments to QFs that exceed the IOU's avoided cost. CAC/EPUC accurately comment that "one of the more effective ways to encourage cogeneration is to enhance payments for delivered electric power."109 However, we are prevented from "enhancing" QF payments if that would exceed avoided cost. Moreover, we are precluded from paying different avoided costs rates for different QFs or different technologies; any standard offer we provide is open to all QFs, regardless of size, location, efficiency, as long as they are certified as a qualifying facility under PURPA.
Our decision in D.04-01-050, relying on City of Ketchican, explicitly recognized that the PURPA purchase obligation is not absolute. D.04-01-050 also refers to FERC's Order No. 69, which states, among other things:
A qualifying facility may seek to have a utility purchase more energy or capacity than the utility requires to meet its total system load. In such a case, while the utility is legally obligated to purchase any energy or capacity provided by a qualifying facility, the purchase rate should only include payment for energy or capacity which the utility can use to meet its total system load. These rules imply no requirement on the purchasing utility to deliver unusable energy or capacity to another utility for subsequent sale.110
FERC has therefore recognized that we must balance the PURPA mandate that utilities purchase energy and capacity from QFs with the overarching requirement that electric utilities may only charge just and reasonable rates for the power they supply to their customers.
RCM Biothane (RCM), Davis Hydro (DH), CARE, and TURN each expressed concern regarding the one MW minimum bid requirement for participation in utility RPS procurement RFOs and request that the Commission adopt a standard offer contract for small generators. (TURN Opening Brief. p. 12; DH Opening Brief, p. 11; RCM Opening Brief, p. 2.)
RCM designs anaerobic digesters for waste-to-energy projects on hog and dairy farms, such that the farms also function as small renewable DG facilities. RCM states that currently, net-metering is the only avenue available for the farms to interconnect to a utility in California, and the net-metering laws do not allow for compensation of excess generation. Under the net metering statutes, the dairy farms can only net-meter against the generation component of the utility bill, and any excess is zeroed out. Because of this, anaerobic digesters are not cost-effective and relatively few farms have chosen to build digesters.
To cure this problem, RCM proposes that the Commission require the IOUs to purchase power from all renewable DGs that are less than one MW in size under standard offer contracts. RCM explains that only a "large scale developer or merchant generator" can meet a one MW requirement in many utility RPS solicitations.
PG&E points out that the net metering program provides credit to certain renewable generators for their exports that offsets the generation portion on the retail amount that would otherwise apply for energy purchased from PG&E. PG&E suggests that generators choosing to install large systems might be better off choosing to sell power rather than participating in net metering.
PG&E also notes that it modified the one MW requirement for its RFOs in 2005 and allows systems smaller than one MW to combine bids to meet the minimum. PG&E encourages dairy farms to pursue this option as an alternative to net metering where, for example, the optimal size of a generator would be larger than the limitations required by the net metering legislation.
PG&E also points out that it is proposing a simplified as-delivered contract form for use with QFs and eligible renewable resources smaller than one MW in dependable capacity. PG&E would pay the QFs at market-based rates for up to a term of five years, therefore, all generators are guaranteed a buyer. The proposed agreement, which PG&E would file for Commission approval, would pay the QFs at market-based rates and contain a term of up to five years.
TURN recommends a maximum size cutoff for this category of 10 MW or the minimum size limit established for the utility's RFOs, whichever is greater. TURN also recommends that QF projects of 25 MW or less that consumes at least 25% of their power internally and sell all of their additional output to the utility should be eligible for longer-term contracts. TURN recommends this option because such QFs cannot sell their surplus directly to the CAISO under its current rules. (Exhibit 149, p. 6, fn. 10.)
Since the initiation of this proceeding, the policy environment has evolved and now offers strong incentives to promote the development of distributed renewable resources. Specifically, D.07-07-027, implemented the provisions of AB 1969, and, in doing so, directed the IOUs to develop feed-in tariffs111 and/or standardized contracts under which eligible renewable resources sell energy generated on site to the IOUs at a price equal to the MPR. These tariffs are available for up to 250 MW of distributed renewable capacity from water and wastewater treatment facilities in all three IOU service territories and an additional 248 MW in the service territories of PG&E and SCE for distributed renewable capacity owned/operated by entities other than water and waste-water treatment facilities. We believe that our implementation of AB 1969 coupled with the contracting options available to QFs of less than 20 MW as described herein, as well as the pressure the utilities are under to procure renewable energy under the RPS program are sufficient to achieve the objectives sought by PG&E and TURN for this particular class of generators and believe that no additional action is warranted at this point.
As already noted, we recently approved two five-year, fixed energy price agreements in D.06-07-032 (PG&E/IEP Settlement) and in Resolution E-4026 (SCE and Renewables). Last year, prior to the announcement of either of these agreements, each of the major QF parties participating in this proceeding (CAC/EPUC, CCC, IEP, and the Renewables Coalition) as well as SDG&E, had recommended that the Commission make available five-year, fixed price standard offers, either as an extension of the existing five-year fixed price mechanism adopted in D.01-03-067, or as a new option for QFs with expiring contracts or new QFs. We observe here that the two recently approved five-year, fixed energy price agreements were a result of bilateral negotiations. The prior five-year, fixed-price contract option at 5.37 cents per kWh, adopted in D.01-06-015, was also largely the result of a bilateral negotiation process.
The QF parties maintain that the 5.37 cents/kWh fixed price has been below posted SRAC prices and the amendments have resulted in substantial ratepayer savings. CCC and the Renewables Coalition point out that the fixed price amendment was "so widely perceived as a good thing, especially for renewable QFs whose economics are not premised on the varying price of natural gas, that the California Legislature codified that right of renewable QFs to negotiate a fixed price, upon expiration of the existing contract amendments, as a price to be set by the Commission. The statute, Pub. Util. Code § 390.1 was enacted in SB 1078."112
The Renewables Coalition suggests that the five-year fixed price should be a five-year forecast of SRAC prices based on the adopted SRAC formula. Eligible QFs would be given a 12-month period in which to elect the fixed price, with the election period commencing either with the expiration of each QFs' existing five-year amendment or, for QFs that do not have five-year amendments, with a month to be assigned that falls within the period during which the existing five-year amendments expire. The Renewables Coalition also recommends that the Commission update as-available capacity and energy pricing terms consistent with CCC's proposal. The Renewables Coalition maintains that Pub. Util. Code § 390.1 requires the Commission to adopt a five-year fixed price option.113
The Renewables Coalition also maintains that adoption of a five-year fixed price contract will not result in oversubscription because the contract would only be offered to QFs that are already built and have operated reliably for many years. The Renewables Coalition further states that utilities' concerns regarding gas price arbitrage do not apply to the renewables QFs and that the IOU can incorporate provisions into the fixed price contract that prevent such gas price arbitrage.
CAC/EPUC recommends that the Commission require the utilities to offer PPAs of five years with a variable or optional fixed energy price and as-available capacity payments. CAC/EPUC recommends pricing the five-year fixed option on the implicit IER in the SRAC energy price and the latest available forward market gas prices at the relevant gas hub. In response to utility concerns that gas-fired QFs executing these contract amendments would sell their gas rather than providing as-available energy under the contract could be addressed through contract provisions stating that during on-peak periods when the power is needed, such activity would be prohibited.
CCC proposes that the renewed fixed price be set using the MIF, with the extended five years of IERs and O&M adders and a five-year forecast of gas prices.
SDG&E also recommends that for existing QF contracts, a multi-year (one-to-five year) fixed price energy option, mutually agreed to via bilateral negotiations, should be permitted. The pricing terms would be for one to five years and would be arranged by mutual agreement based on border gas forward prices and SRAC energy price transition formula as determined in this proceeding.
SCE and PG&E both oppose the adoption of a mandatory new fixed price option based on a five-year forecast of SRAC. In support of their position, SCE and PG&E maintain that PURPA does not allow state regulatory authorities to revise binding contractual agreements in QF contracts; therefore, any mandated substitution of the fixed price for SRAC in existing contracts would be unlawful. In addition, they note that the five-year fixed price option is not required by statute. Instead, § 390.1 provides:
Any nonutility power generator using renewable fuels that has entered into a contract with an electrical corporation prior to December 31, 2001, specifying fixed energy prices for five years of output may negotiate a contract for an additional five years of fixed energy payments upon expiration of the initial five-year term, at a price to be determined by the Commission.
PG&E does not oppose negotiating a fixed price with QFs, but opposes any mandated fixed price. We agree that the option provided under § 390.1 does not undermine the RPS program because the generators who have access to this program are existing renewable generators. Therefore, while a contract extension would ensure that the utilities' baseline RPS resources did not disappear, it would not bring new renewable resources on line, a key objective of the RPS program. Moreover, although these resources would then be removed from the RPS solicitations, that result may allow new resources to compete more effectively, possibly bringing new renewable resources on line in California.
Moreover, the statute does not require the Commission to make available a standard offer with five-year fixed prices, it merely requires the Commission to approve the pricing terms agreed upon in the negotiation of the contract. Many QF contracts were originally modified to provide energy payments based on fixed prices, rather than SRAC as a result of contract amendments approved in D.01-07-031. Recently, many more QF contracts were modified to provide an additional fixed price period in D.06-07-032 and Resolution E-4026. We adopted both these contract amendments recognizing that they were the result of negotiations involving many factors in addition to the SRAC formula. These amendments are not precedential.
At this point, we are not in a position to adopt a mandatory five-year fixed price based on contract terms that have yet to be negotiated. We encourage any renewable resources to negotiate and bring before us applications for such five-year, fixed price amendments, wherever possible, and will consider such applications as we have other negotiated agreements in prior decisions, keeping in mind the direction provided by § 390.1.
The CAISO requests that the Commission require QFs executing new PURPA contracts to comply with CAISO tariff requirements. The CAISO also requests that the Commission specify that QFs seeking to interconnect or modify an existing interconnection at the transmission level should be required to comply with the CAISO's interconnection process.114
The IOUs agree and also request that the Commission relieve the IOUs from the obligation to act as scheduling coordinators for QF power purchase contracts. SDG&E notes that existing QFs, already interconnected with the utility under an expiring contract, should not require additional interconnection studies, but PG&E maintains that QFs who have substantially modified their facilities as well as QFs with new PPAs should comply with the procedures and standards of the CAISO.
The QF parties believe that subjecting QFs to the CAISO tariffs would be an unreasonable burden for QFs, especially for cogenerators that have host thermal obligations and smaller QFs that may not be able to afford the various additional costs required for tariff compliance. They argue that neither the CAISO nor the utilities have argued that they will incur significant additional costs in handling the scheduling for QFs with new or renewed contracts. They also argue that there is no evidence that continuing to exempt QFs from the CAISO tariffs causes any problems.
The CAISO submits that if regulatory must-take status is removed, it will respect the QFs preexisting status and not subject them to burdensome tariff requirements but noted, that such treatment "may require action by the CAISO in conjunction with the California Commission's action." (RT 4127:27-4128:6.)
On this issue, we are guided by Key Action Item 7 of Section 4 of EAP II, which provides: "Adopt a long-term policy for existing and new qualifying facility resources, including better integration of these resources into CAISO tariffs and deliverability standards."
For Small QFs whose size prevents them from participating in CAISO markets, it is clear that the utilities should continue to be obligated to act as scheduling coordinators. It is less clear for larger QFs, who may or may not have the capability to perform these functions. A more critical question, however, is whether or not the costs of scheduling and imbalance charges are avoided by the utility through its purchases from the QF. PG&E claims that these are not avoided costs and that any power purchased, whether from QFs or other market participants would need to be scheduled. It is possible that in the case of purchased power, the seller would perform the scheduling function, but in that case, the cost would be built in to the cost of the energy.
We find that QFs should generally be required to comply with CAISO tariff requirements, however, as recommended by the CAISO and SDG&E, we do not expect existing QFs to be required to complete new interconnection studies. As observed by several parties, neither the CAISO nor the utilities have described what type of disruption would be caused by retaining QFs' existing arrangements, and in fact, CCC points out that the Kern River Cogeneration Company (KRCC) contract would extend KRCC's existing interconnection agreements for the term of that contract, five years. The current "CAISO exempt" and "must-take" status of the QF contracts stems from the fact that the CAISO did not exist when the contracts were signed. New contracts must explicitly take the existence of the CAISO and its tariff requirements into account. We adopt PG&E's recommendation that QFs one MW or greater should be required to comply with the CAISO tariffs. We also adopt PG&E's recommendation that QFs serve as their own scheduling coordinators, with the option of purchasing these services from the utility.
CAC/EPUC maintains that IOUs must continue to provide standby power and recommend that the Commission adopt standby power policies that reflect certain CEC and FERC policies regarding the location of metering and telemetry for QF projects. CAC/EPUC are opposed to the CAISO's preferred approach which would require gross metering or net generation metering. CAC/EPUC note that FERC found that the CAISO need only meter the direct impact on its system; "changes in load and generation behind the meter will be captured at this point." (CAC/EPUC Opening Brief, p. 39.) The IOUs do not disagree, but note that issues of standby policies and rate design are outside of the scope of this proceeding.
For purposes of our prospective QF Program, we will continue to require the IOUs to provide backup or standby power at reasonable rates to QFs. Standby rate design issues have been considered and adopted as part of the Commission's Distributed Generation Rulemaking and are not further considered in this proceeding.
102 Exhibit 102, p. 74.
103 Id., p. 76.
104 See Appendix A for a brief description of the various standard offers.
105 See, D.02-08-071, p. 31, addressing a QF request to continue SO1 contracts.
106 D.96-10-036, mimeo., p. 40.
107 Id.
108 SCE Brief, p. 8., citing N. Little Rock Cogeneration, L.P. 72 FERC at 62, 170-172.
109 Exhibit 134, p. 43.
110 45 Fed Reg 12219 (1980).
111 In general, a feed-in tariff provides a specific price, defined in the tariff, under which a DG system owner sells their system's output to a utility, and purchases electricity to meet their onsite electricity needs at the applicable retail rate.
112 CCC Opening Brief, p. 43.
113 Section 390.1 states "[A]ny nonutility power generator using renewable fuels that has entered into a contract with an electrical corporation prior to December 31, 2001, specifying fixed energy prices for five years of output may negotiate a contract for an additional five years of fixed energy payments upon expiration of the initial five-year term, at a price to be determined by the commission."
114 CAISO, August 17, 2005 Comments, p. 2.
