II. Background
On December 20, 2004, the Commission issued D.04-12-048 that adopted Long-Term Procurement Plans (LTPP) for PG&E, SCE and San Diego Gas & Electric Company (SDG&E) and provided direction to the utilities on the procurement of the resources identified in the LTPPs.
Western Power Trading Forum (WPTF), IEP and The Utility Reform Network (TURN) responded to PG&E's PTM; PG&E responded to SSJID's PTM; the Office of Ratepayer Advocates (ORA), the Cogeneration Association of California and Energy Producers and Users Association (CAC/EPUC), the Alliance for Retail Electric Markets and the Western Power Trading Forum (AReM/WPTF), the California Large Energy Consumers Association (CLECA) and the California Manufacturers and Technology Association (CMTA), California Retailers Association (CRA), IEP, and Department of Water Resources (DWR) responded to SCE's PTM; and TURN, PG&E, SCE and WPTF responded to IEP's PTM.
Numerous parties also filed Applications for Rehearing of D.04-12-048. On September 8, 2005, the Commission issued D.05-09-022 granting limited rehearing on one issue: The 50/50 sharing mechanism on construction cost savings. This issue will be included in the scope of the 2006 LTPP.
A. SCE's PTM
SCE's PTM seeks clarity, correction, and modification of D.04-12-048 on the following issues:
1. Stranded Cost Recovery
SCE requests that the decision be modified to state that the investor-owned utilities (IOUs) may recover incremental costs of new non-renewable [renewable portfolios standard (RPS)] resources for the life of the commitment (instead of the maximum limit of ten years) from all customers, regardless of their present service provider.1
WPTF/AReM, CAC/EPUC, ORA, CLECA/CMTA and CRA recommend that SCE's petition be denied. WPTF and AReM agree that the cost recovery provisions of D.04-12-048 should be clarified, but disagree with SCE's requested modification. ORA states that the decision was clear in its intent and CLECA/CMTA do not find any inconsistency in Commission decisions.
In its reply, SCE clarifies that it seeks cost recovery from all customers for transactions executed to maintain system and local area reliability.
Our determination in D.04-12-048 is clear: Departing customers are expected to pay for the resources their utility acquired while in service over either 10 years or the duration of the resource contract, whichever is shorter. D.04-12-048 also provided for the "opportunity [for the utilities] to justify in their applications, on a case-by-case basis, the desirability of adopting a cost recovery period of longer than ten years for their non-RPS resource commitments.2
As far as the system reliability is concerned, D.04-12-048 already provides that: "Cost recovery for that portion of a resource acquired by the utilities to meet local reliability needs should be recovered from all customers."3
This is consistent with the process we already established in D.04-07-028 where we stated:
"We expect the IOUs to attempt to recover appropriately allocated reliability-related costs through their FERC Reliability Services tariff provisions. If utilities are denied recovery through this channel, utilities may seek cost recovery in the appropriate ERRA proceeding. We expect utilities to bring the matter to us with adequate time for reasonable consideration and decision."4
Therefore, we find no need to modify D.04-12-048 in this respect and deny SCE's request. We will however, take this opportunity to correct an inadvertent clerical error by replacing Ordering Paragraph (OP) 10 to correctly reflect the conclusions reached by the Commission in this decision.5
We are replacing the first sentence of OP #10 that currently reads: "We adopt the 15-year standard for new fossil-fueled resources acquired by the utilities." with "We adopt a ten-year, or life of the contract standard, whichever is less, for new fossil-fueled resources acquired by the utilities." (New language in italics.)
2. Affiliate Transactions
SCE requests (1) that the Decision clarify the length of the affiliate transactions, which are not subject to affiliate transaction ban; and (2) that the IOUs be permitted to purchase power from affiliates on a short-term basis after a long-term contract with an affiliate expires.
IEP and ORA recommend the denial of the second request. Both parties find the PTM without merit and SCE's request unjustified.
We defined the duration of short-term and long-term transactions in response to PG&E's PTM D.03-12-062, which coincides with SCE's suggested definition. The same definition should be used in the context of the affiliate transaction ban as well. That is, "short term" covers up to and including three calendar months, or one quarter. We reiterate that the ban is lifted for those long-term transactions that are executed through an open and transparent solicitation process.
We will not allow the utilities to extend transactions with affiliates on a short-term basis. We allowed transactions with the affiliates provided that those transactions are entered into with an open and transparent process. As we have already noted, we will not have the same oversight over a short-term extension that might be conducted under volatile market conditions. Utilities should make their planning in advance and execute their plans accordingly.
3. Modifications to D.03-12-062
In D.04-12-048, we granted 10 of the 12 modifications requested by SCE to D.03-12-062, referring to them by their requested number, rather than reciting the language of all the modifications granted. We specifically denied requested modifications seven and nine. (See OP 16.) In its PTM, D.04-12-048, SCE requests that we modify D.04-12-048 to set forth with specificity the language of the modifications granted to D.03-12-062.
That, however, is not all that SCE requested in relation to the modifications to D.03-12-062. In its PTM, D.04-12-048, SCE states that "several of the modifications adopted need to be further clarified or modified relative to what SCE originally proposed."6
Upon careful reflection, we have determined that due to the passage of time, not only would it be impractical to "clarify or modify" the modifications, but that we are now denying an additional two requested modifications to D.03-12-062: Modifications one and five - those related to audits and DWR cost allocation. We will discuss those further below.
Requested Modification One to D.03-12-062, asked for the imposition of a timeframe for the Commission's review of quarterly transaction reports. D.04-12-048 granted that modification, but did not identify a timeframe, rendering the modification meaningless. In the PTM, D.04-12-048, SCE asked not only for the imposition of a timeframe, but amended the modification request to ask that audits paid for by the utilities only cover the 2004 quarterly transaction reports. The review of quarterly advice letters is subject to the procedure established in D.04-12-048, OP 25. Since OP 25 does not set forth any time limits, we clarify that our intent was not to impose a timeframe, so we are denying requested Modification One.
In addition, we are specifically denying SCE's request to limit the use of auditors to the 2004 quarterly transaction reports. Following the quarterly advice letter approval process established in D.04-12-048, OP 25, it is up to the Energy Division (ED) Director to decide whether hiring an auditor is necessary and to determine the scope of the review. The auditor should be paid for by the utilities and charged to their ERRA accounts. This auditor practice should continue through 2006, and/or until modified by Commission decision. Clarifying that the audits may continue through 2004, 2005, 2006 and into the future, and that the audits will be paid for by the utilities and booked in the ERRA account will provide certainty for all parties, and will expedite the ED's ability to hire an auditor.
Requested Modification Five asked that D.03-12-062 be modified to be consistent with SCE's current treatment of DWR costs in its adopted procurement plan. We deny this requested modification as D.03-12-062 has been superceded by D.05-06-060 that addresses this issue.
In summary, we grant eight of the 12 modifications requested by SCE to D.03-12-062, denying numbers one, five, seven and nine. D.04-12-048 indicated that we were granting 10 of the 12 requested modifications. We modify D.04-12-048 accordingly, changing the language in the text7 and OP 16 as follows:
"We grant ten of SCE's proposed twelve requested modifications ..." is replaced with "We grant eight of SCE's proposed twelve requested modifications . . . ."
And the text setting forth the paragraphs that are denied is modified to include:
3. Modify language that would set a specific time for issuing a resolution for the approval of the IOUs quarterly compliance filings.
4. Modify language to limit the use of an auditor to transactions entered into during 2004.
5. Modify language to be consistent with SCE's current treatment of DWR costs. (New language in italics.)
OP 16 in D.04-12-048 currently reads: "We grant ten of SCE's 12 requested modifications, as requested in its Petition to Modify, with the exception of modifications seven and nine." This language should be replaced with the following new OP 16: We grant eight of SCE's 12 requested modifications, as requested in its Petition to Modify, with the exception of modifications one, five, seven and nine, as discussed in this decision. (New language in italics.)
4. Further Clarifications
SCE requests that its view on the Greenhouse Gas (GHG) adders be changed to correctly state the utility's position. No parties objected to SCE's request. We grant SCE's request. Currently the decision reads as follows at p. 182: "However, since that time SCE has modified its stance and now supports the GHG adder to the evaluation of new utility commitments or contracts with terms greater than five years." We modify the section on p. 182 as follows:
However, since that time SCE has modified its stance and now supports the GHG adder to the evaluation of new utility commitments or contracts with terms greater than five years. SCE believes, however, that application of GHG adders only to California IOUs is a "sub-optimal program." SCE believes that there should be a broader national or regional program and has called in a press release for "comprehensive national programs" to address GHG. (New language in italics.)
SCE also asks that language in the decision be modified to clarify that SCE does not have a short-term and a long-term procurement plan but a single AB 57 plan. We grant SCE's request, but believe that with this affirmation the language in the decision, at p. 118 does not need to be modified as it states:
". . . SCE has one AB 57 procurement plan which is a component of SCE's LTPP showing in this proceeding . . . ."
B. PG&E and IEP's PTM: Cost Cap for Utility-Owned Resources
As referenced earlier in D.05-09-022, the Commission granted limited rehearing of D.04-12-048 on the sharing of cost cap savings. This issue will be part of the scope of the 2006 LTPP. We review the petitions filed by PG&E and IEP together since they address similar issues.
In its PTM, PG&E asks for the elimination of the cost cap established in D.04-12-048 and the reaffirmation of the cost-of-service ratemaking for reasonably incurred cost of new generation. PG&E lists the following reasons for the Commission to modify the adopted cost cap structure: (1) The existing safeguards such as all-source solicitation requirement, IE and PRG review are sufficient and the cost cap is unnecessary to compare utility-owned projects with PPAs; (2) a cost cap is not justified by the concern that the IOUs will game the solicitations by presenting lower bids only to seek cost overruns later; (3) eliminating risk of overruns might lead to greater chance of higher savings for shareholders and fewer benefits for the ratepayers; (4) cost-of-service generation works better.8
If the cost cap is not eliminated, PG&E suggests two modifications: (1) if an IOU demonstrates that the costs exceeding the cap are reasonable, prudent and in the public interest, the cap should be subject to adjustment; and (2) the cap should be optional and symmetrical, i.e., the cost overruns and savings should be shared equally between ratepayers and shareholders. In addition, PG&E requests that the decision be modified to clarify that the IOUs can negotiate a PPA or utility-owned projects outside of the competitive process.
IEP argues in its PTM that the Decision creates a bias in favor of utility-owned plants. IEP is particularly concerned that utilities may not reflect non-capital costs, such as O&M, planning, administrative, and financing in their bids because they plan on recovering these costs through the traditional ratemaking mechanism. Therefore, IEP requests that all costs be reflected in the bid, and the cost cap be applied not only to capital costs, but to all cost components. IEP also suggests that any cost savings be allocated to the shareholders only.
TURN supports PG&E's PTM in part and opposes IEP's PTM. TURN supports a hybrid-market consisting of both utility-owned and non-utility owned resources, and a diversified portfolio of PPAs and utility-owned resources. TURN opposes IEP's PTM because IEP's proposal would "convert the utility into just another market bidder," eliminating "the ability to obtain power at the cost of providing it."9 TURN does not support other aspects of PG&E's PTM. TURN prefers that the Commission allow for cost-based utility-owned generation, but subject to balanced reward and penalty structures that are developed on a case-by-case basis. TURN is concerned that under the mechanism set by the Commission, the utility will either refuse to propose any new generation or bid high to cover all foreseeable risks, and that the symmetrical sharing may help mitigate the problem only to a certain extent. TURN recommends that utilities be allowed to propose cost-based generation through a CPCN and the application include an opportunity for competitors to offer alternatives to the proposed utility project.
WPTF recommends the rejection of PG&E's PTM. WPTF points out that (1) cost cap is necessary to protect ratepayers from cost overruns; (2) utilities should not be allowed to bypass the competitive process; and (3) cost of service generation may work but it is not the best alternative for the ratepayer. If the Commission allows the IOUs to update their costs or removes the cost cap, WPTF requests the same treatment for independent generators.
WPTF supports the proposed modifications in IEP's PTM, while SCE and PG&E oppose them. PG&E points out that capital costs are the most predictable expenditures over the depreciation life of a plant. PG&E adds that the estimation of costs in the short run is possible; however, the assumptions might change in the long run and fuel costs review, general rate cases, etc., ensure that ratepayers do not have to pay a premium in advance. PG&E states that the Commission has already created a disincentive for the utilities to invest in new resources, and IEP's proposal will make it harder to recover the costs that are impossible to estimate over the lifetime of a project.
SCE recommends rejection of IEP's PTM and believes that "while the Decision failed to recognize all of the differences between utility-owned and IPP-owned generation, the decision to allow a utility to recover ongoing costs through cost-of-service ratemaking was not incorrect." (Page 4.)
We deny both PG&E and IEP's PTMs. The Commission is determined to support open and transparent transaction processes, and holding utilities to their bids helps keep the playing field level. As stated in the Decision, the IOUs will not be allowed to file a CPCN for a project unless it is selected in a solicitation. The IOUs do have a good assessment of what the market bears, therefore they could plan in advance to submit a bid in a solicitation. This will help ensure that the solicitations process is open, fair, and transparent. TURN's proposal, in which the IOU files a certificate of public convenience and necessity and the other parties have the opportunity to provide competitive offers might lead to lengthy litigation, cross-case comparisons, and delay the resource acquisition efforts, which is an important goal for the State at this time.
We will not modify our decision on the cost cap structure and the sharing mechanism. We agree with TURN that diversified portfolios help to minimize market risk as well as other types of risk. Both utility-owned and IPP-owned generation bring unique benefits and risks. Therefore, it is important that we sustain the cost cap to help keep the playing field level, but, as TURN suggests, we will not treat the regulated utilities as simply another bidder in the market. We imposed the cost cap on only the capital cost because as expressed in PG&E's response to the Motion, it is the most significant portion of the total cost and the most accurately estimated cost component.
C. SSJID's PTM
1. Irrigation Districts/Community Choice Aggregations/Municipalities
SSJID requests in its petition that the treatment provided for Community Choice Aggregations (CCAs) in D.04-12-048 be extended to municipalities and irrigation districts. Specifically, SSJID asks the Commission to develop protocols to be used by utilities for determining the dates upon which and the conditions under which a municipal utility's liability for utility power purchases would end in cases where the municipal utility (or irrigation district) begins purchasing its own power. R.04-12-048 stated our commitment to determining these matters for CCAs as part of our inquiry in R.03-10-003.
PG&E responded to SSJID's petition, stating that SSJID would substantially modify the decision by extending a policy for CCAs to other types of entities. PG&E argues that CCAs, irrigation districts and municipal utilities have different statutory obligations and that the Commission has not addressed related legal and policy issues as they would apply to irrigation districts and municipal utilities.
PG&E is correct. In particular, R.03-10-003 addresses issues specifically germane to CCAs and the scope of that proceeding does not include policies regarding irrigation districts and municipal utilities. It might be appropriate to apply the principles we adopt for CCAs in R.03-10-003 to irrigation districts and municipal utilities, but this proceeding, R.04-04-003 is not the appropriate forum for that determination, and we cannot modify our decision to include this discussion, since these issues were not part of the scope of the LTPP proceeding. Irrigation districts and municipal utilities should participate in the 2006 LTPP proceeding and ask that a discussion of the protocols and policies for their interests be part of the scope of the proceeding so that a record can be developed to address these issues.
D. IEP's Motion to Clarify D.04-12-048: Independent Evaluator
IEP filed a motion on April 15, 2005 and requested clarification on the IE selection process; criteria that will be used to evaluate PPAs and utility-owned generation submitted in response to solicitations; weight to be given to the IE's assessment; and clarification of "all-source" solicitations.
Calpine and WPTF support the motion, while CARE, SCE, and PG&E request its denial.
Independent Evaluator: IEP is particularly concerned about the impartiality of the IE, because an IE, who is hired and paid by the utility, may tend to agree with the utility's resource choices. WPTF agrees with IEP in that the IE should not be selected solely by the utility and suggests that the Energy Division or the PRG identify and select the IE. On the other hand, according to SCE, "there is no need to establish prescriptive requirements for selecting an IE or how an IE will perform his/her function."10
The Commission set the rules in D.04-12-048, provided sufficient guidelines in the selection of an IE, and gave the opportunity to parties to comment on the use of IE and related issues. We agree with SCE in that "establishing more prescriptive standards on the selection process will simply limit flexibility and introduce delays at a time when the IOUs and the Commission are trying to facilitate essential procurement activities on the most appropriate terms possible."11 The Commission's contracting process might lag behind IOUs procurement process, thereby causing unintended delays in resource procurement.
In its response to the Motion, PG&E acknowledges the role of the Energy Division and the PRG members in its IE selection process. We authorized the IOUs to contract directly with IEs, provided that they act under the oversight of the Energy Division. The current mechanism should provide sufficient checks and balances. As stated in D.04-12-048, we will revisit the issue at a later time, and if any actual deficiency in the mechanism is observed, we will make the necessary modifications at that time.
The evaluation method to be used in competitive solicitations is stated in D.04-12-048: "The IOUs will implement a least cost best fit methodology when evaluating PPAs and utility-owned bids in an all source open (RFO), taking into account all quantitative and qualitative attributes of each bid." (Page 127.) We will not prescribe further details at this time.
The Role of Exclusions in All-Source Solicitations: In its response, Calpine expresses its support for the motion, and states that PG&E's RFO and SCE's draft RFO eligibility requirements limit participation in the solicitation due to the specified operational date requirement. Calpine argues that procurement costs will likely increase because: (1) excluding resources from the solicitation decreases competition, which reduces downward pressure on prices; (2) an excluded resource could be the least cost resource; (3) project owners may believe that they must recover all project costs and investment return over one contract period because projects may not be eligible for the subsequent long-term contracts. Consequently, future investment will be discouraged due to the risk that there might not be contracts after the initial contract period.
According to SCE, all-source does not necessarily mean that IOUs must solicit contracts for existing resources when an IOU has a need for new generation. PG&E does not see limiting the RFO to future resources as an impediment to competitive pricing. PG&E issued an RFO for the existing power plants and expects to procure power from existing plants.
In D.04-12-048, Section VIII(D), on Comparing PPAs to Utility Ownership, the Commission set forth several solicitation bidding guidelines. The first guideline clearly defines "all resources" and does not make any distinction between new and existing resources:
"All resources (IOU-built, Turnkey, Buyout, and PPA) must participate in an all-source or RPS solicitation. However, the IOUs have the flexibility to tailor their RFOs to reflect their specific resource needs (i.e., IOU-built, turnkeys, buyouts, and PPAs do not need to participate in every all-source and RPS solicitation)." (D.04-12-048, p.128.)
This guideline does allow IOUs to "tailor their RFOs to reflect their specific resource needs," however, it is unclear to us as to how a utility can tie any of its resource needs to only new or only existing generation types. In fact, a megawatt-hour is a megawatt-hour, and a kilowatt-hour is a kilowatt-hour (green power and Renewables Portfolio Standard issues aside), regardless if it was generated from a `new' or `existing' resource. Utility resource needs are met with a utility's own utility-retained generation resources, and with various power products like 7x24 and 6x16 power contracts, spot purchases, and tolling agreements. Some power contracts are unit-contingent while others are not tied to a specific generation resource. Standard and non-standard power products are performance- specific, not age-specific.
Perhaps the utilities are concerned that, if existing plants were allowed to compete with new plants, the existing generators may be tempted to not bid their cost and `inflate' their bids up to, yet under, the expected cost of the new generation. If this occurred, existing generation could beat out new generation on price and could slow the development of new capacity. However, bidding what the market will bear is one feature of a competitive market.
It is correct that the Commission allowed the IOUs to tailor their RFOs based on their needs, and the need for new generation starting at a future date might be a valid argument for the restriction imposed in PG&E's RFO. However, it is also correct that exclusion of certain resources will decrease competition and might affect the prices. D.04-12-048 established solicitation bidding guidelines, but it did not make a distinction between old and new generation and all-resource solicitation referred to types of resources such as IOU-built, turnkey, buyout and PPAs.
Even though there is merit to utilities' reasoning, the all-source solicitation should encompass all existing and future resources and should not bar any entity from participating in the RFO. 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.
1 Conclusion of Law (COL) 16 states that: "The utilities should be allowed to recover stranded costs for their non-RPS resource commitments from departing load over either the life of the contract or 10 years, whichever is less. The ten-year recovery period should also apply to any utility-owned generation acquired as a result of the procurement process, commencing once the resource begins commercial operation. Stranded costs arising from RPS procurement activities should be collected from all customers, including departing load, over the life of the contract. . . ."
2 COL 16.
3 COL 16.
4 D.04-12-048, p. 24.
5 D.04-12-048, pp. 55-63, Findings of Fact (FOF) 30-38 and COL 16.
6 SCE's PTM D.04-12-048, p. 9.
7 D. 04-12-048, p. 109.
8 PG&E's PTM, pp. 2-3.
9 TURN's response to IEP and PG&E's PTM, p. 4.
10 SCE's Response, p. 1.
11 SCE's Response to IEP's Motion, p. 3.
