12. Additional Changes and Clarifications Required in Light of Subsequent FERC Orders
12.1. Overview
The FERC Declaratory Order states that the AB 1613 program is not preempted by the FPA or PURPA as long as: (1) the CHP generators from which the CPUC is requiring the Joint Utilities to purchase energy and capacity are QFs pursuant to PURPA; and (2) the rate established by the CPUC does not exceed the avoided cost of the purchasing utility."26 Furthermore, FERC clarifies that "any ruling on the extent of federal preemption of the CPUC's AB 1613 program does not apply to public agency sellers that are exempt from Commission jurisdiction under section 201(f) of the FPA."27
In addition, the FERC Clarification Order supports a wide degree of latitude for the Commission to establish a utility's avoided cost; found that the concept of a multi-tiered avoided cost rate structure is consistent with the avoided cost requirements set forth in Section 210 of PURPA and FERC regulation; and recognizes that full avoided cost need not be the lowest possible avoided cost and can properly take into account real limitations on alternate sources of energy imposed by state law.28
The significance of the FERC's Clarification Order is that in contrast to its Southern California Edison Company decisions in the 1990s, where FERC required states to consider purchases from "all sources," including coal-fired generation, in setting avoided costs, the FERC's Clarification Order rules that all sources can be limited to those that are available to the utilities under state law.29
12.2. Amended Scoping Memo and Party Comments
In consideration of the FERC Declaratory Order, the Commission's September 2010 Amended Scoping Memo asked parties to comment on two QF-related questions:
1. What changes are necessary to the contracts approved under D.09-12-042 to reflect the requirement for QF certification in addition to the already mandated certification from California Energy Commission (CEC)?
2. If a QF already certified for and participating in the
feed-in-tariff program loses its CEC certification under
AB 1613 but maintains QF certification by FERC, what should the contract provide as the alternative rate for the QF (e.g., should the QF receive short run avoided cost pricing)?
Both SCE and PG&E commented generally that the Amended Scoping Memo failed to address the most critical question regarding how the Commission should set an avoided cost for the AB 1613 program consistent with PURPA. Both utilities recommended that the Commission take action to harmonize AB 1613 implementation with the Commission's other avoided cost proceedings.
As to the specific questions raised, several parties commented that the contract should be amended to ensure that the Seller is in compliance with QF requirements. PG&E suggested specific changes to the definition of "eligible CHP facility" to address this issue. Furthermore, CCDC and FCE point out that public entities need not obtain QF certification and any contract changes should make this clear. SCE suggests that all QFs, including the AB 1613 QFs, utilize the QF standard contract developed in accordance the global QF Settlement.
Regarding the event that a QF loses its AB 1613 certification, CCDC, San Joaquin, and FCE contend that the QF would be eligible for the applicable QF rate, namely Short Run Avoided Cost as developed in D.07-09-040. SDG&E and PG&E contend that in such a situation, the facility would be in default of a material term of the contract and no longer entitled to participate in the AB 1613 program.
12.3. The Record Reflects That The MPR-Based Price Is An Avoided Cost
While outside the scope of the Amended Scoping Memo, we respond first to the PG&E and SCE implication that the MPR-based priced adopted in D.09-12-042 is not an avoided cost and that the Commission must therefore calculate an avoided cost here.
It is true that the MPR-based price was adopted at a time when the Commission took the position that the AB 1613 CHP program was not subject to PURPA. However, this point is irrelevant. The legitimate question is not when the AB 1613 price was adopted, or under what circumstances, but whether or not the record demonstrates that the AB 1613 price is an appropriate avoided cost. Notwithstanding its belief when it issued D.09-12-042 that the AB 1613 program did not need to be implemented pursuant to PURPA, the Commission confined itself to an MPR-based price in order to comply with AB 1613's ratepayer indifference standards. As the Joint Utilities argued in their first rehearing application:
By definition, "avoided cost" should be the measure of ratepayer indifference. That is, if ratepayers are simply paying the price they would have otherwise paid "but for" the AB 1613 purchase, they are indifferent to the existence of the AB 1613 tariff.30
We agree with the Joint Utilities. In D.09-12-042 we found that the MPR-based price, as a reasonable proxy for the generation the utilities would have purchased "but for" the AB 1613 purchase requirements, met the ratepayer indifference standard of AB 1613. By the Joint Utilities' own definition, it is also a finding of avoided cost.
The MPR is intended to represent the long term market price of electricity for fixed price contracts.31 The MPR is derived from the construction, operating and maintenance costs associated with a highly efficient 500 MW CCGT. The MPR inputs and methodology were developed pursuant to Public Utilities Code § 399.15(c) through a public process and the Commission relies on a public process to periodically update the MPR inputs and methodology.32
Based on this history of the MPR, and the fact that many of the pricing components of the MPR correspond to AB 1613's pricing requirements,33 the Commission found in D.09-12-042 and affirmed in D.10-04-055 that the MPR's CCGT is the unit most likely to be procured by the utilities in the absence of the AB 1613 procurement obligation.34 Because the Commission has found that a price based on the MPR's CCGT unit most closely approximates the costs avoided by procuring energy from AB 1613 CHPs, and the utilities have failed to present a reasonable argument that this is not the case, we find that the MPR-based price will not exceed the utilities' avoided costs and that the Joint Utilities' claim is without merit.
12.4. QF Status and Two Tier Pricing Structure
In light of the FERC Declaratory Order, CHP facilities not exempt from FERC jurisdiction, which are participating in the AB 1613 feed-in-tariff program, must obtain QF status under PURPA requirements in order to be eligible for the avoided cost rates assigned by the Commission. The requirement to obtain QF status does not preclude the requirement for a CHP facility to also obtain certification from the CEC that it meets the higher efficiency standards as prescribed in AB 1613.
We agree with PG&E's suggested edits to the definition of "eligible facility" as applicable to address this issue. Specifically, we adopt the following change to the definition of "eligible facility" in the standard and simplified contracts for AB 1613:
"Eligible CHP Facility" means a facility, as defined by Public Utilities Code Section 2840.2, subdivisions (a) and (b) that,
(1) meets the guidelines established by the California Energy Commission pursuant to Public Utilities Code § 2843 and,
(2) meets the requirements of 18 Code of Federal Regulations
§ 292.201, et seq., if applicable.
In the event that a facility is decertified by CEC, we agree with parties that this constitutes an event of default of the AB 1613 feed-in tariff rates under the contract. However, the CPUC cannot decertify a facility from its QF status; only the FERC can decertify a QF. If a facility were to fall below the minimum
AB 1613 contract requirements, but still meet the requirements needed to retain its QF status, it would still be eligible to obtain a QF standard offer contract with a short-run avoided cost rate as ordered in D.07-09-040, if still in effect, or participate in any programs that supersede D.07-09-040. In no event may a utility unilaterally declare a default under the AB 1613 contract without the CEC decertifying the facility, just like a utility may not unilaterally declare a QF is in default under a QF contract without the FERC finding that the facility has lost its QF status. If the utility believes that a QF is not in compliance with federal standards, the utility may petition FERC to revoke the QF's status.35
In this regard, consistent with the "flexible pricing mechanisms," which the Ninth Circuit found were proper remedies for states36 and the "multi-tiered avoided cost rates structure," which the FERC Clarification Order explained states may adopt for CHP generators,37 we find that an AB 1613 compliant CHP facility is entitled to the AB 1613 pricing formula provided herein. However, in the event of decertification by the CEC, the contract should provide that the CHP generator should then be entitled to the established short-run avoided cost rate at the time of the CEC's decertification, and the utility should offer the CHP generator the standard offer contract associated with that rate. To the extent that the FERC were to revoke the QF status of the CHP generator, then the utility's obligation would be governed by the remedy provided at the time of the FERC's revocation of QF status. The utilities are directed to modify the AB 1613 contracts to be consistent with this discussion.
12.5. A PURPA Contract May Include Sanctions For Non-Compliance With State Efficiency Requirements
As described above, AB 1613 CHPs are to receive the MPR-based price so long as they comply with AB 1613. Should they fail to comply with AB 1613, but retain their QF status, they will receive payments pursuant to the most current short-run avoided cost. SCE objects to this two tier pricing structure. Citing Independent Energy Producers Association v. CPUC (9th Cir. 1994) 36 F.3d 848, 857-58, SCE argues that this two tiered price is unlawful "to the extent the Commission seeks to apply an `alternative' avoided cost rate to AB 1613 QFs based simply on the CEC's higher efficiency standards for AB 1613 CHP."38 We disagree. So long as the two prices in the two tier pricing structure do not exceed the utilities' avoided cost, and payment is based on contract compliance, SCE's claim has no merit.
The state may require higher efficiency from CHPs, and pay a lower avoided cost for failure to meet these requirements; such a program advances both state and federal goals to encourage efficient CHPs. Both PURPA and the Energy Policy Act of 2005 (EPAct 2005), like AB 1613, recognize CHPs as a special class of highly efficient facilities, with EPAct 2005 expressly directing FERC to consider revising its CHP criteria to ensure "continuing progress in the development of efficient electric energy generating technology."39 Several courts have also acknowledged, with approval, the efficiency benefits of CHPs. In particular, the U.S. Supreme Court upheld FERC's decision to pay "full avoided costs" to CHPs and other small power producers as a development incentive to encourage fuel efficiency:
... it was not unreasonable for the Commission to prescribe the maximum rate authorized by PURPA. The Commission's order makes clear that the Commission considered the relevant factors and deemed it most important at this time to provide the maximum incentive for the development of cogeneration and small power production, in light of the Commission's judgment that the entire country will ultimately benefit from the increased development of these technologies and the resulting decrease in the Nation's dependence on fossil fuels. ...The basic purpose of § 210 of PURPA was to increase the utilization of cogeneration and small power production facilities and to reduce reliance on fossil fuels.40
The Supreme Court in American Paper also recognized that "a qualifying facility and a utility may negotiate a contract setting a price that is lower than a full-avoided cost rate."41
Given the holdings of American Paper, SCE's reference to Independent Energy Producers as a barrier to the AB 1613 CHP two-tier payment structure is both inaccurate and inapposite here. American Paper clearly supports the two-tier payment structure we adopt here, and the holdings of Independent Energy Producers are irrelevant to the issue. Independent Energy Producers focused on QF status determinations, and whether a state could delegate QF status determinations to the utilities. It determined that only FERC could make a QF status determination, and thus the delegation was improper. In that context, the Court noted that a state could not sanction a QF for failure to meet federal QF efficiency standards. The QF status issues addressed by Independent Energy Producers are not at issue here; compliance with state law requirements is at issue. To the extent that a QF does not comply with state efficiency standards, that is up to the state to police and this is properly done through contracting requirements that provide sanctions for failure to comply.
We recognize that, consistent with Independent Energy Producers, we may not revoke a facility's QF status, delegate that authority to a utility, or reduce the price paid to below avoided cost, and we do not attempt to do so here. To the extent that the price adjustment terms for failure to meet state efficiency requirements are reflected in the AB 1613 contract, and that both the high and low prices are avoided costs, it is a valid provision that meets both state and federal efficiency goals and the holdings in Independent Energy Producers do not preclude us from establishing such a structure.
12.6. The 10% Location Bonus Is Based On The Utilities' Avoided Costs
D.09-12-042 provides that an AB 1613 CHP located in a local resource adequacy area shall be paid a 10% location bonus calculated based on its total energy payment. The Joint Utilities have repeatedly argued that there is no basis for this 10% location bonus. The decision first denying rehearing on this issue, D.10-04-055, explained that the basis for the payment was the value of deferred transmission and distribution (T&D) upgrades, as well as the value of local grid stability and reliability:
[D.09-12-042] determines that a 10% location bonus is appropriate in constrained areas because CHP sited in these areas would provide system benefits such as transmission and distribution upgrade deferrals and local grid stability and reliability.42
While D.10-04-055 cited to the record to generally support this conclusion, it did not explain the avoided cost basis for the 10% location bonus. In other words, there was no showing of utility avoided costs that justified the 10% number. This is because the Commission at that time was not implementing the program pursuant to PURPA.
In light of the FERC orders, it is clear that D.09-12-042 must be clarified to explain the basis for the 10% location bonus adopted there. In summary, there is a record basis for the 10% location bonus, which was based on an "actual determination" of the utilities' avoided T&D costs. The 10% location bonus reflects extremely conservative assumptions that assures it will, in no event, exceed the utilities' avoided T&D costs. The discussion below shall be incorporated into D.09-12-042 to clarify the record and analysis on this issue.
12.6.1. Record On The 10% Location Bonus
At the initiation of this rulemaking, the California Cogeneration Council (CCC) filed comments noting that the Commission currently uses a model to calculate average T&D avoided cost values for each utility's service area, by each utility division or planning region.43 CCC provided, as Attachment A to its comments, a sample of the T&D avoided costs calculated for each utility by the model (CCC Attachment A). The spreadsheet model is commonly referred to as the "E3 Model" in the parties' comments. To calculate T&D avoided costs, the E3 Model relies upon each utility's marginal T&D costs adopted in their general rate cases.
Based on the avoided cost numbers reflected in Attachment A, CCC proposed to pay an avoided T&D cost "adder" to AB 1613 generators located in areas that would produce higher than average avoided cost benefits to ratepayers, but did not specifically identify the amount of the adder.44 CCC proposed that the generators would cooperate with the utilities to identify the best areas to site such projects to generate the highest avoided costs. In making this proposal, CCC acknowledged that the utilities have traditionally argued against such a T&D avoided cost on the basis that such costs are "highly site-specific and that a case-by-case analysis is needed."45 CCC noted that "to the CCC's knowledge, no CHP or renewable projects have ever been compensated for such locational benefits."46
In commenting on the CCC's proposal to identify T&D avoided costs, all three utilities agreed that distributed generation facilities have the potential to avoid T&D costs; however, each one argued that this proceeding was not the forum for quantifying those costs.47 Among other things, they argued, as CCC anticipated, that each DG facility must be considered separately, on a case-by-case basis, to calculate such avoided costs. None of the utilities suggested that the E3 Model avoided cost calculations provided in the CCC Attachment A were inaccurate.
On August 4, 2009, an Administrative Law Judge's ruling incorporated the Final Staff Proposal into the record of the proceeding and requested party comments on the proposal. The Final Staff Proposal suggested a 10% location bonus under both proposed pricing options for any eligible CHP located in a distribution or transmission constrained area. The Final Staff Proposal reasoned that CHP systems situated in constrained areas could provide system benefits such as transmission and distribution upgrade deferrals and local grid stability and reliability. The Final Staff Proposal asked parties to comment on how to determine location or distribution constrained areas for purposes of applying this bonus.
SCE and PG&E/TURN argued that the proposed location bonus of 10% was unsupported by analysis and unreasonable.48 They also asserted that the "locational marginal price" (LMP) values in the CAISO market are the only accurate reflection of actual congestion and losses on the grid.49 SCE also pointed out that adopting a generic location adder would be inconsistent with the generator-specific methodology adopted in D.03-02-068.50
SDG&E/SoCalGas contended that if certain facilities received a bonus because of their favorable location, then facilities located in less than favorable locations should receive less.51 SDG&E/SoCalGas also contended that CHP located in its service territory is more valuable than CHP located elsewhere in the CAISO-controlled grid given the need for local resources in their service territory. They argued that locational value should only be provided to CHP located in areas with local resource adequacy requirements when contracting with the local utility.52
CCDC and FCE supported the Final Staff Proposal's location bonus. CCDC and FCE suggested that the location bonus should be provided to any location where the CAISO nodal LMP exceeds the zonal price.53
12.6.2. Analysis of the 10% Location Bonus
Historically, the Commission has agreed with the utilities that while distributed generation facilities unquestionably generate avoided T&D costs, a facility-specific analysis was required before a T&D avoided cost could be paid to generators. The Commission has therefore previously declined to adopt a uniform avoided cost calculation for T&D. Instead, D.03-02-068, issued February, 2003, established four facility-specific criteria to be met for a facility to qualify for avoided T&D costs. To our knowledge, which is consistent with CCC's, no facility has ever qualified for T&D avoided costs under this test.
Notwithstanding the determinations in D.03-02-068, the Commission's position on this matter has evolved over the last eight years in other proceedings so that today the E3 Model is used to calculate avoided T&D costs to determine the cost effectiveness of the utilities' energy efficiency and demand response programs.54 The utilities benefit from the inclusion of uniform avoided T&D costs in these programs. The more cost-effective the program, because of the addition of T&D avoided costs, the more money utility shareholders may receive in the form of performance incentives.
We previously found merit to SDG&E/SoCal Gas's contention that a location bonus is appropriate for generators located in areas with local resource adequacy (RA) requirements. As a result, we adopted a 10% location bonus for eligible CHP systems located in CAISO-identified location-constrained resource areas, which the Commission identifies as Local RA areas for purposes of establishing local RA procurement requirements.55
The Local RA program, approved in D.06-06-064, is intended to ensure that the utilities have acquired sufficient generation capacity to serve defined, transmission constrained local areas. Each year the Commission adopts Local RA requirements and identifies Local RA areas based on the CAISO's annual study of local capacity requirements.56 The CAISO study identifies the specific substations included in each Local RA area - constrained areas that require the purchase of a specified amount of Local RA resources to avoid T&D system failures.
In D.09-12-042, we determined that eligible CHP interconnected within any of the identified Local RA areas should receive the location bonus. We required each utility to make these location bonus areas, including the specific substations included in each area, publicly available on its website. This information is required to be updated each year upon adoption by this Commission of the Local RA program requirements.57 The location bonus is to be applied for the entirety of an AB 1613 CHP's contract term based on the Local RA areas identified in the year the contract is executed.
To the extent that parties believe that the 10% location bonus does not reflect avoided cost, or will push the MPR-based price above avoided cost, they are wrong. As an initial matter, it should be noted that all of the utilities agree that distributed generation, which includes AB 1613 CHPs, results in avoided T&D investment. Nevertheless, the 10% location bonus will only be made available to new AB 1613 facilities constructed in Local RA areas. AB 1613 CHPs located in these Local RA areas will generate avoided costs to the utilities well above the 10% location bonus the utilities will pay them.
CCC Attachment A sets forth utility-specific avoided T&D costs by geographic "divisions" which average $5.60/MWh for PG&E's service area, $6.66/MWh for SCE's service area, and $13.03/MWh for SDG&E's service area, assuming a baseload profile, which is the profile of an AB 1613 generator. Based on these average avoided costs for T&D, a 10% location bonus paid to CHP facilities located in Local RA areas for avoided T&D investment is a conservative estimate of the actual T&D costs avoided in Local RA areas for several reasons.
First, the 10% location bonus is only paid on the amount of energy sold to the utility, and not on the amount of energy that the utility avoids producing due to the existence of the AB 1613 generator. Thus, the AB 1613 CHP will receive a payment for far less than the T&D costs it actually avoids. For example, when a utility achieves 10 MWh in energy efficiency savings, it gets credit for 10 MWh of avoided T&D costs, measured by the E3 Model and reflected in the CCC Attachment A. However, if an AB 1613 generator generates 10 MWh of energy, but only sells 1 MWh to the utility, while it avoids 10 MWh of generation, and thus, produces savings similar to 10 MWh of energy efficiency, the AB 1613 generator is only paid the 10% location bonus on the 1 MWh sold to the utility. Pursuant to AB 1613, generators must size output to load and may only sell their excess power to the utility. Thus, any payment to an AB 1613 generator for avoided T&D costs will be less than actual T&D costs avoided.
Second, the CCC Attachment A averages calculated from the data provided in the E3 model are based on avoided T&D investment in the entire utility service area. The 10% adder will only be paid to generators located in Local RA areas, which are the most constrained resource areas and will therefore have the highest avoided T&D costs. For example, CCC Attachment A shows that avoided T&D costs are as high as $9.17/MWh in PG&E's service area, $8.33 in SCE's service area, and $13.03 in SDG&E's service area. In that regard, the 10% Location Bonus based upon "average" T&D costs is a conservative estimate of the cost actually avoided by the utility for T&D. Further, the avoided T&D costs reflected in CCC Attachment A are likely to increase as a result of utility filings for increases in transmission rates at FERC, and increases in distribution rates in Commission proceedings.
In adopting the 10% location bonus for AB 1613 generators located in local RA areas, the Commission recognizes that it must be consistent with federal law. The FERC Clarification Order explained that if the adder is based on an actual determination of expected costs of T&D upgrades it would constitute an avoided cost determination and be consistent with PURPA and Commission regulations:
[I]f the CPUC bases the avoided cost "adder" or "bonus" on an actual determination of the expected costs of upgrades to the distribution or transmission system that the QFs will permit the purchasing utility to avoid, such an "adder" or "bonus" would constitute an actual avoided cost determination and would be consistent with PURPA and our regulations.58
Further, the Commission has a great deal of discretion in determining this expected avoided cost. As the Ninth Circuit Court of Appeals recognized in Independent Energy Producers, the Commission has broad authority to implement Section 210 of PURPA, "states play the primary role in calculating avoided costs," and states have "a great deal of flexibility ... in the manner in which avoided costs are estimated ..."59 FERC recently affirmed and further clarified these principles in its Clarification Order. There, it emphasized the fact-specific nature of avoided cost determinations and its reluctance to "second guess" state determinations:
As the Commission has previously explained, "states are allowed a wide degree of latitude in establishing an implementation plan for section 210 of PURPA, as long as such plans are consistent with our regulations. Similarly, with regard to review and enforcement of avoided cost determinations under such implementation plans, we have said that our role is generally limited to ensuring that the plans are consistent with section 210 of PURPA...." [See American REF-FUEL Company of Hempstead, 47 FERC ¶ 61,161, at 61,533 (1989); Signal Shasta, 41 FERC ¶ 61,120 at 61,295; see also LG&E Westmoreland Hopewell, 62 FERC ¶ 61,098, at 61,712 (1993).] In this regard, the determinations that a state commission makes to implement the rate provisions of section 210 of PURPA are by their nature fact-specific and include consideration of many factors, and we are reluctant to second guess the state commission's determinations; our regulations thus provide state commissions with guidelines on factors to be taken into account, "to the extent practicable," [18 C.F.R. § 292.304(e) (2010)] in determining a utility's avoided cost of acquiring the next unit of generation.60
The U.S. Supreme Court's holdings in American Paper further support the Commission's determination to adopt a uniform T&D avoided cost in the form of the 10% location bonus, instead of requiring the project-specific determination of prior years. In that case, the Supreme Court found that FERC appropriately adopted a uniform rule that every CHP was entitled to full avoided cost payments. Among other things, the Supreme Court referred to PURPA's legislative history stating that such rate determinations should not be subject to the same level of scrutiny typically applied to utility rate applications. The Supreme Court quoted that legislative history at length, including the directive to encourage CHPs:
"[C]ogeneration is to be encouraged under this section and therefore the examination of the level of rates which should apply to the purchase by the utility of the cogenerator's or small power producer's power should not be burdened by the same examination as are utility rate applications, but rather in a less burdensome manner. The establishment of utility type regulation over them would act as a significant disincentive to firms interested in cogeneration and small power production."61
The Supreme Court examined FERC's policy reasons for adopting the full avoided cost rule, instead of a generator-specific avoided cost. Among them, the Supreme Court recognized FERC's desire to provide development incentives, and that such development would serve the public interest:
The Commission recognized that the full-avoided-cost rule would not directly provide any rate savings to electric utility consumers, but deemed it more important that the rule could "provide a significant incentive for a higher growth rate" of cogeneration and small power production, and that "these ratepayers and the nation as a whole will benefit from the decreased reliance on scarce fossil fuels, such as oil and gas, and the more efficient use of energy." [footnote omitted] 45 Fed. Reg. 12222 (1980).62
The Supreme Court properly noted that "[t]he Commission would have encountered considerable difficulty had it attempted to determine an appropriate rate less than full avoided cost."63 Similarly here, the Commission's project-specific T&D adder has proven to be unworkable. To encourage CHP consistent with both federal and state law, the Commission adopts a uniform rule here to compensate AB 1613 CHPs located in Local RA areas for some portion of the T&D costs they allow the utility to avoid. Such a uniform rule is consistent with both FERC orders, and the Supreme Court's holdings in American Paper.
In summary, the 10% location bonus the Commission adopted in D.09-12-042 is consistent with FERC's regulations because it is based on an "actual determination" of the utilities expected T&D costs, as established in their general rate cases and incorporated into the E3 Model relied on here. Based on these costs, and as explained above, the 10% location bonus is a conservative under-estimate of the avoided T&D costs associated with AB 1613 generators situated in location constrained resource areas and will not result in AB 1613 generators receiving more than avoided costs for their energy sales to the utilities.
26 California Public Utilities Commission et al., 132 FERC ¶ 61,047 at 67.
27 Id. at 71.
28 California Public Utilities Commission et al., 133 FERC ¶ 61,059 at 26-30.
29 Id. at 30.
30 Joint Utilities' Rehrg. App. January 20, 2010, at 12-13.
31 Pub. Util. Code § 399.15(c)(1).
32 See, e.g., D.05-12-042; D.07-09-024; D.08-10-026; and the Commission's MPR website at http://www.cpuc.ca.gov/PUC/energy/Renewables/mpr
33 See Final Staff Proposal at 10.
34 D.09-12-042 at 35; D.10-04-055 at 8-9.
35 Independent Energy Producers Association, Inc. v. CPUC (9th Cir. 1994) 36 F.3d 848, 859.
36 Id.
37 California Public Utilities Commission, 133 FERC ¶ 61,059 at 30.
38 SCE Comments, September 29, 2010, at 5-6.
39 See, e.g., 18 C.F.R. § 292.205 and 16 U.S.C. §824a-3(n)(1)(A)(iii) (emphasis added); see also Conf. Rep. No. 95-1750, pp. 97-98 (1978).
40 American Paper Inst. v. American Elec. Power (American Paper) (1983) 461 U.S. 402, 417-418.
41 Id. at 416.
42 D.10-04-055 at 10.
43 CCC Comments, July 31, 2008.
44 CCC Comments, July 31, 2008, at 10-14 and Attachment A.
45 CCC Comments, July 31, 2008, at pp.12-13.
46 CCC Comments, July 31, 2008, at p. 13.
47 See, e.g., SCE Comments, August 15, 2008, at 4 ("Thus, although SCE would agree that generation systems can be used to defer T&D investment, it is unlikely that this could or should be accomplished through enactment of this tariff.."); PG&E Comments, August 15, 2008, at 7 (PG&E "agrees that, in situations where CHP units truly allow a utility to avoid T&D costs, a benefit exists for its customers that would warrant paying an additional amount. However, as the Commission has previously determined, such `right place, right time' situations may be fairly rare, and depend on a number of conditions being met for a T&D value to exist."); see also, SDG&E/SoCal Gas Comments, August 15, 2008, at 2 (outlining SDG&E's 4 criteria proposal for when a facility may qualify for T&D avoided costs, adopted in D.03-02-068).
48 PG&E/TURN Comments, August 24, 2009, at 13; SCE Comments, filed August 24, 2009, at 12.
49 PG&E/TURN Comments, August 24, 2009, at p.13; SCE Comments, filed August 24, 2009, at p. 14.
50 SCE Comments, August 24, 2009, at 12-14.
51 SDG&E/SoCalGas Comments, August 24, 2009, at 6.
52 SDG&E/SoCalGas Comments, August 24, 2009, at 6.
53 CCDC Comments, filed August 24, 2009, at 9; FCE Comments, filed August 24, 2009, at 9.
54 The E3 Model for calculating avoided costs for energy efficiency was adopted in D.05-04-024 and updated in 2008 to apply to the utilities' 2009-2011 energy efficiency portfolio plans. (Assigned Commissioner's and Administrative Law Judge's Ruling, R.06-04-010, April 21, 2008.) These updates did not include changes to the methodology for calculating avoided T&D.
55 D.09-12-042 at 38-39.
56 The CAISO's 2008 Local Capacity Requirement (LCR) Study is available from the CAISO website, http://www.caiso.com/1c44/1c44bbc954950.html
57 2010 Resource Adequacy program requirements were adopted by this Commission in D.09-06-028.
58 133 FERC ¶ 61,059 at 31.
59 Independent Energy Producers Association, supra, 36 F.3d 848, 856.
60 133 FERC ¶ 61,059 at 24.
61 American Paper, supra, at 414, quoting from H. R. Conf. Rep. No. 95-1750, pp. 97-98 (1978).
62 Id. at 415.
63 Id. at 416.
