XX. Background

In previous decisions, The Commission authorized the following products and transaction processes:

	Authorized by D.02-10-062 and/or D.03-12-062
Transactions	(authorized by D.02-10-062) Ancillary Services Capacity (demand side) Capacity (purchase or sale) Electricity Transmission Products Financial call (or put) option Financial swap Forward Energy (demand side) Forward Energy (purchase or sale) Forward Spot (Day-Ahead & Hour-ahead) purchase, sale, or exchange Gas Purchases (monthly, multi-month, annual block) Gas Storage Gas Transportation Transaction Insurance (Counterparty credit insurance, cross commodity hedges) On-site energy or capacity (self-generation on customer side of the meter) Peak for off-peak exchange Physical call (or put) option Real-time (purchase or sale) Seasonal exchange Tolling Agreement
Additional Transactions	(authorized by D.03-12-062) Counterparty Sleeves Emissions Credits futures or forwards Forecast Insurance FTR Locational Swaps Gas Purchases (daily) Non-FTR Locational Swaps Structured Transactions Weather triggered options
Transactional Processes	(authorized by D.02-10-062) Competitive Solicitations (Requests for Offers) Direct bilateral contracting with counterparties for short-term products (i.e., less than 90 days) Inter-Utility Exchanges ISO markets: Imbalance Energy, Hour Ahead, and Day Ahead (when operational) Transparent exchanges, such as Bloomberg and Intercontinental Exchange Utility ownership of generation (interim rules set in D.04-01-50)
Additional Transactional Processes	(authorized by D.03-12-062) Open Access Same-Time Information Systems (OASIS) Negotiated bilateral contracting allowed for Short-term transactions of less than 90 days duration and with delivery beginning less than 90 days forward. Longer-term non-standard products provided that the IOU include a product justification in quarterly compliance filings Standard products in cases where there are 5 or fewer counterparties (for gas storage and pipeline capacity, only Transparent exchanges to include voice and on-line brokers

In its Petition to Modify (PTM) D.03-12-062, filed February 20, 2004, PG&E asks the Commission to clarify that for purposes of upfront standards for procurement transactions, "short term" means up to and including 3 calendar months, or one quarter, not "90 days". PG&E also wants a clarification that the IOUs can conduct competitive solicitations in an auction format. PG&E argues that the use of online auction techniques for competitive procurement falls within the guidelines presented in D.03-12-062 and D.04-01-050.

In response to PG&E's PTM, ORA agreed with the short-term definition, but opposed electronic auction authority since the proposal lacks details.

On February 19, 2004, SCE filed a Petition for Modification (PFM) of D.03-12-062 (the 2004 Short Term Procurement Plan Decision). SCE's PFM presented argument on twelve separate issues in the D.03-12-062 that, SCE contends, affect its ability to procure power and make it difficult for SCE to comply with portions of the decision as it is written. SCE's list of twelve requested modifications are set forth in its LTPP, Vol.2, p.13-16, which we will not reiterate here. SCE, like PG&E, raised the 90-day vs. one quarter issue.

We grant PG&E's PTM and clarify that D.03-12-062 authorized IOUs to conduct procurement using negotiated bilateral agreements for transactions of up to three calendar months, or one quarter, forward; and that utilities will consult with their PRGs for transactions with delivery periods of greater than three calendar months, or one quarter. We further clarify that D.03-12-062 authorized IOUs to conduct procurement using an electronic auction format for execution of competitive solicitations, among other transactional methods. The authorized products are good for short-, medium-, and long-term procurement.

We grant ten of SCE's twelve requested modifications with the exception of modifications seven and nine, as shown here:

1. "Modify language that would require an "unqualified certification" as a basis for authorizing SCE's proprietary risk model. The language of the decision must be modified because a certification of this level would be extremely difficult to obtain."

2. "Eliminate the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges. Allowing transactions from brokers only when the same transaction can be made with an exchange at an equivalent price is impractical."

With regard to an "unqualified certification" of SCE's proprietary risk model, we are not asking that the model be proven infallible. We are simply seeking an independent review of the internal validity of the model, that all the features of the model work as advertised, that the model is mathematically sound, and that the assumptions utilized by the model are reasonable.

With regard to the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges, this is a reasonable upfront standard, consistent with AB57. The use of transparent exchanges is one reasonable check on the competitiveness of a portion of SCE's procurement activity. We direct SCE to consult with its PRG regarding the specific implementation options that are available.

A. SCE'S AB 57 Plan

SCE states that its proposed revision to its Existing AB57 Procurement Plan⁹² is a component of it's long-term procurement plan. SCE further clarifies that it does not have a separate AB57 long-term procurement plan and AB57 short-term procurement plan. Instead, SCE has one AB57 procurement plan which is a component of SCE's LTPP showing in this proceeding (SCE LTPP, July 9, 2004, Vol.2, p.1). SCE states that the objective for each IOU's AB57 procurement plan is to set the limits (i.e., the upfront achievable standards and criteria called for in AB57), within which the IOU's transaction activity would be deemed reasonable. All transactions and actions that fall within the boundaries of an AB57 procurement plan are compliant with the approved procurement plan and accordingly are assured cost recovery. Statute requires that a procurement plan contain upfront achievable standards and criteria (Id., p.1-2).

On February 19, 2004, SCE filed a Petition for Modification (PFM) of D.03-12-062 (the 2004 Short Term Procurement Plan Decision). SCE's PFM presented argument on twelve separate issues in the D.03-12-062 that, SCE contends, affect it's ability to procure power and make it difficult for SCE to comply with portions of the decision as it is written. SCE's list of twelve requested modifications are set forth in its LTPP, Vol.2, p.13-16, which we will not reiterate here. SCE, like PG&E, raised the 90-day vs. one quarter issue.

We grant ten of SCE's twelve requested modifications with the exception of modifications seven and nine, as shown here:

3. "Modify language that would require an "unqualified certification" as a basis for authorizing SCE's proprietary risk model. The language of the decision must be modified because a certification of this level would be extremely difficult to obtain."

4. "Eliminate the requirement that SCE demonstrate that identified over-the-counter (OTC) brokers provide prices equivalent to those of exchanges. Allowing transactions from brokers only when the same transaction can be made with an exchange at an equivalent price is impractical."

With regard to an "unqualified certification" of SCE's proprietary risk model, we are not asking that the model be proven infallible. We are simply seeking an independent review of the internal validity of the model,that all the features of the model work as advertised, that the model is mathematically sound, and that the assumptions utilized by the model are reasonable.

B. Policy Issues Related To Long-Term Plans

The 2000-2001 energy crisis can undoubtedly be considered the antithesis of an open, transparent, and competitive bidding process. Fortunately, the California utilities are moving forward in a new hybrid market structure developed in large part by this Commission. Since the crisis, the Commission has authorized, and the utilities have conducted, a number of all-source and renewable power solicitations which have successfully procured thousands of megawatts of power under short- and long-term contracts to serve California customers. However, not all parties agree on how the solicitations should be conducted. Although all parties tend to agree that the solicitations should take place by way of an open, transparent and competitive bidding process, not all parties agree on the specific definitions, details and logistics of such a competitive process. We want the IOUs to have a mixed portfolio of demand and supply side resources, and a combination of renewables and fossil- fuel sources, as well as different ownership types.

We have determined that it is time to allow greater head-to-head competition and hereby lift the affiliate ban on long-term power products. Accordingly, we adopt certain guidelines and safeguards, including an independent third party evaluator requirement. We will allow the consideration of debt equivalence in the bid evaluation process as specified herein, and we will also require the use of a carbon adder as a bid evaluation component. With these policies we continue to shape and define the hybrid power market in California so as to advance the positive benefits of competition.

C. Proposals Regarding Open And Transparent Competitive Bidding Process

1. Parties Positions

Calpine states that a lack of head-to-head competition and PG&E's 50/50 proposal are not features of an open, transparent, and competitive bidding process and will not ensure procurement of LCBF resources. In particular, Calpine is concerned that since IOU-owned resources generate earnings for the utility, there is an inherent incentive for IOUs to favor IOU-owned resources over third party PPAs, a fact that was recognized in Decision 04-01-050.⁹³ Calpine further adds that there is a "fundamental difference in the allocation of risk and the certainty of bid prices between IOU-owned projects and PPAs allows IOUs to unfairly advantage IOU-owned projects vis-à-vis PPAs in the bid evaluation process."⁹⁴ Since an IOU can shift the risk of cost overruns and other problems related to the development, construction and operation of a project to ratepayers means that the IOUs' bid strategies are not constrained by normal bid considerations, such as being responsible for the economic consequences of submitting a low bid that is ultimately selected in the solicitation process. Calpine asserts that the only solution to this inequity is to require the IOU to `commit' to the cost and operating performance estimates it uses in its bid evaluation of the IOU-owned project.

CMTA/CLECA share similar concerns about utility-owned generation contending that (1) "utility-owned generation constructed without the benefit of a competitive solicitation has been too costly" [and that] the Commission has long experience with cost overruns associated with utility-owned generation, citing Diablo Canyon, SONGs, and Helms Pumped Storage [in particular;]" and (2) that "a competitive bidding process also obviate[s] the need for after the fact reasonableness reviews." Lastly, CMTA/CLECA observe that SCE refuses to sign "contracts for terms longer than three years until the debt equivalence issue is resolved," yet the SCE recently received approval for "a 30-year power purchase agreement with its affiliate-to-be ... the Mountainview project"⁹⁵

In addition, CMTA/CLECA claim that the participation of an IOU affiliate can greatly detract from an open, transparent, and competitive bidding process. As a solution, CMTA/CLECA recommend the use of a independent third party evaluator, as set forth in The FERC's competitive solicitation guidelines⁹⁶ which provide specific guidance on transparency, power product definition, evaluation, and oversight.

PG&E and Edison both object to parties having more access to confidential information, which is what some parties believe "open and transparent" means.

With regard to competition, SCE is opposed to head-to-head competition between PPAs and utility-owned generation . SCE contends that "there are important differences between utility-built and independent generation, which are extremely difficult to quantify and evaluate in the same process. The primary differences include the value of operational control, operational and financial risk, special local area needs, flexibility in case of changed circumstances, and the terminal and refinancing value associated with utility plant."⁹⁷

SDG&E is understandably amenable to an open, transparent, and competitive bidding process that includes direct as it recently concluded an all-source grid reliability RFP that netted six new resources that included demand and supply side sources and different ownership schemes. The utility argues that "[g]iven the wide range of possible offers, however, the Commission should not attempt to predetermine specific methodologies for all future solicitations in this regard. Instead, the Commission should reinforce the objective that a utility seeking approval of a new resource should provide a robust comparison of options that maintains a level playing field for all bidders. The PRG can also play an important role here in advising the utility on its competitive solicitation activities, which is yet another reason that the PRG process should be extended."⁹⁸

Sempra supports all-source solicitations and states that "the Commission should require that proposed utility-owned generation projects be competitively bid against other market solutions."⁹⁹

WPTF recommends that long-term procurement efforts by the utilities must include the following mandatory competitive bidding requirements:

o Evaluation of bids should include all incremental costs delivered to load;

o Any procurement process in which the utilities can submit their own bids must be unbiased;

o RFPs should be mandatory for utility procurement;

o Barriers to transmission development that supports markets and fuel diversity should be removed; and

o Winning bids should be binding and non-recourse.¹⁰⁰

Strategic Energy supports open and transparent competitive bidding for any new medium- and long-term resource needs. Strategic urges the Commission to reject PG&E's [50/50] proposal . There is simply no guarantee that set-asides would result in least-cost procurement for bundled customers. Generally, lower costs result from the consideration of the greatest number of procurement options.¹⁰¹

2. Discussion and Determinations

Our most recent experience with procurement solicitations was the SDG&E Grid Reliability RFP process that involved head-to-head competition among both supply-side and demand-side resources (megawatts and negawatts), peaking and baseload resources, an affiliate resource, renewable generators, a merchant PPA, and utility turn-key power plants. This was our first experience with such diversified head-to-head competition among competing resource types, yet it was a successful undertaking.

In Governor Schwarzenegger's October 8, 2004 energy plan letter published in the San Diego Union-Tribune,¹⁰² the Governor spoke about SDG&E's RFP and said:

"...it is the ability of utilities to engage in long-term contracts that attracts investors and gets power plants built. In [June 2004], the PUC approved [the SDG&E Grid Reliability RFP results in D.04-06-011,] a plan designed to meet San Diego's energy needs through this decade. The plan includes building two large power plants that will generate 1,085 megawatts of power. (One megawatt powers roughly 1,000 homes). Two more facilities planned for San Diego, one of which is a renewable biomass facility, will bring an additional 85 megawatts." (Governor Schwarzenegger, Energy Plan Letter, October 8, 2004)

D. Requirements for an All-Source Solicitations

· All-source open solicitations need to be transparent and competitive, and in addition, need to be open to all resources (conventional/renewable - turnkeys, buyouts, and PPAs).

· Following the "loading order" contained in the Joint Agency Energy Action Plan is the first priority for IOU resource procurement, meaning that energy efficiency and demand-side resources should be employed first. When these opportunities are exhausted, renewable generation is to be procured to the fullest extent possible - whenever an IOU issues an RFO for generation resources, it must be prepared to defend its selection of fossil gener.

· IOUs are directed to procure the maximum feasible amount of renewable energy in the general solicitations authorized by this decision, and will be allowed to credit this procurement towards their Renewables Portfolio Standards (RPS) targets in 2005 and beyond. If an IOU succeeds in procuring sufficient renewable resources to meet its 2005 RPS Annual Procurement Target (APT) via an all-source RFO, it will not be required to undertake an RPS-specific solicitation next year.

· The IOUs will employ the Least-Cost Best-Fit methodology when evaluating PPAs and utility-owned bids in an all-source open RFO, taking into account the qualitative and quantitative¹⁰³ attributes associated with each bid.

· Green House Gas (GHG) adders are to be used for fossil bids in all-source open RFOs.

· Debt equivalency will be considered when evaluating individual PPA bids, regardless of whether the bids are from a fossil, renewable, or an existing QF resource. IOUs are not to consider resource-specific debt equivalency risk factors in their cost of capital proceedings but should instead use the methodology outlined in this decision.

· IOUs will not be allowed to recover costs in excess of their final bid price for utility-owned resources.

· The IOUs will be required to use a 3^rd party evaluator in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders.

E. Affiliate Transactions

D.04-01-050 continued the ban on affiliate transactions, however, our position on this issue warrants re-examination at this time.

"We do not have the same level of oversight and authority over affiliate transactions that we do over direct utility operations. We recognize that cross-subsidies and anti-competitive conduct has occurred in the past in affiliate procurement transactions and that it could occur in the future under the market structure we adopt here"^[1]

As noted earlier in this decision, SEGE argues for the Commission to rescind the ban on affiliate transactions since it prevents utility access to ready built facilities owned by an affiliate. As we have already found in the Mountainview proceeding, A. 03-07-032, D. 03-12-059, and in the SDG&E RFP proceeding, A. 03-10-007, D. 04-06-011, affiliates can present attractive procurement options.

Calpine, DENA, IEP, and WPTF do not oppose affiliate participation in resource solicitations, provided that certain safeguards are in place like a requirement for third party evaluators. In D.04-01-050, ORA recommended that the affiliate ban not extend to long-term transactions:

"ORA states that the Commission should continue the ban on affiliate transactions for short-term procurement because the short-term market moves too fast and there is too great of a potential for abusive self-dealing, with little or no possibility for Commission oversight of these types of transactions. However, for long-term transactions, such as long-term PPAs or a turn-key agreement or take-over of a power plant, the Commission should evaluate these transactions under the current affiliate rules. ORA testifies this process should have enough built-in protections to prevent potential self-dealing and other abuses." (D.04-01-050, p.69-70)

Given our desire to consider all competitive options, instead of continuing the ban, and carving out exceptions for unique resources from time to time, we now find that it is in the best interest of the ratepayers and consumers to allow for a full vetting of all available resources in a RFP. We will institute appropriate safeguards for the solicitations for long-term transactions, in part through continuation of utility PRGs and through the use of independent third-party evaluators. Such safeguards can protect consumers from any anti-competitive conduct between utilities and their affiliates. Therefore, by this decision we lift the ban on long-term affiliate transactions for transactions entered into through an open and transparent solicitation process. However, we maintain the ban on short-term transactions because the short-term market moves too fast and there is too great of a potential for abusive self-dealing, with little or no possibility for Commission oversight of these types of transactions.

We also reaffirm that the utilities, and in particular their respective risk management committees, maintain complete procurement planning independence from their affiliates. In D.04-01-050, we found that such procurement planning independence was severely lacking for SDG&E:

"Exhibit 70 shows (1) that 7 of the 9 members of SDG&E's Electric and Gas Procurement Committee are from Sempra Energy Utilities (SEU), the parent of SoCalGas and SDG&E; (2) Sempra's Energy Risk Management Oversight Committee, the analytical platform supporting enterprise-wide energy risk-management activities, contains members from both the regulated and unregulated affiliates; and (3) Sempra's Project Review Committee, which reviews and approves all transactions in excess of $10 million and commitments with important policy implications, has no members from SDG&E or SoCalGas and only one member from SEU on an 11 member committee." (D.04-01-050, p.72)

* * *

"Even without the benefit of examples of any harm to SDG&E customers from including Sempra personnel, we find that including such people on a committee to evaluate procurement options for the ratepayers is troubling. Sempra officers have a foot on each side of the firewall, partly representing SDG&E's customers, and partly representing the affiliates. To protect the appearance as well as the fact of affiliate separation, we think there should not be affiliate or holding company personnel involved in utility procurement decisions of the utilities."

"We are also troubled by SDG&E's procurement risk management committee being dominated by SEU officers. SDG&E has extremely competent management and it is this management whose duties should include assuring that procurement activities are undertaken in the most appropriate and economical manner."

"Therefore, we direct that SD&E file a revised Exhibit 70 to reflect that the risk management committee(s) overseeing SDG&E's electric procurement operations and DWR-related gas procurement operations are comprised solely of SDG&E management. This filing should be by Advice Letter within 30 days. We may review this finding after completion of the SDG&E/SoCalGas/SEU audit, as discussed below." (D.04-01-050, p.73-74)

F. Procedures, Rules And Protocols, Including Independent Third-Party Evaluators

The use of Independent Third-Party Evaluators or `IEs' in resource solicitations has not been previously required by the Commission. Parties disagree on the role, scope, and need for an IE. Some parties contend that the role of an IE is currently being fulfilled through the PRG. The IOUs are opposed to the delegation of any final decision-making authority to an IE.

As noted by WPTF, FERC has recently set forth Guidelines for Reviewing Future Section 203 Affiliate Transactions, which include guidelines for IEs in 108 FERC 61,081 (July 29, 2004). FERC explained that to the extent to which a utility demonstrates that its RFP process follows the stated guidelines, its application processing time (including litigation) will likely be reduced, thus increasing the possibility of more timely Commission approval through an adequate showing under the Edgar standard.¹⁰⁴ In short, guidelines will allow FERC to more easily identify transactions that are consistent with the public interest, and, therefore, expedite their approval.¹⁰⁵

The FERC guidelines provide for substantial IE involvement in resource solicitations at the "design, administration, and evaluation stages of the competitive solicitation process." FERC has set forth "minimum standards for assuring independence and the scope of the third party's role." These IE guidelines are shown here:

"A minimum criterion for independence is that the third party has no financial interest in any of the potential bidders, including the affiliate, or in the outcome of the process.¹⁰⁶ Preferably, the independence criterion would be the same as that of an ISO or RTO.¹⁰⁷ In this context, "independence" means that the third party's decision-making process is independent of the affiliate and all bidders.¹⁰⁸ Without such independence, the third party could be biased towards the affiliate in order to enhance its financial position. Obviously, a similar concern could arise regarding an actual or potential financial interest link between the third party and any potential bidder. Independence can also be satisfied if the state commission has approved the selection of a third party on the basis of established independence criteria. In addition, the third party should not own or operate facilities that participate in the market affected by the RFP.

"The independent third party should be able to make a determination that RFP process is transparent and fair, and that the RFP issuer's decision is not influenced by any affiliate relationships. For example, if the RFP issuer wishes to use a collaborative RFP design process, the independent third party should be the clearinghouse for comments by potential bidders on a draft RFP and should evaluate those comments as possible revisions to the RFP. The independent third party's role as the sole link for transmitting information between potential bidders and the RFP issuer would also help to ensure that the RFP design will not favor any particular bidder, particularly an affiliate. The independent third party should continue to be a conduit of information between utility and bidders in determining which of the original bid responses are qualified bids or may be included in a short list.

"At the evaluation stage of the RFP process, the third party should be able to credibly assess all bids based on both price and nonprice factors. It should be able to consider both generation asset bids and power purchase agreements. Also, it should be able to independently verify transmission characteristics that may limit the suitability of certain alternatives. The third party should have access to the same information that the RFP issuer uses in its evaluation and should be able to independently verify its correctness. The third party should also be able to evaluate nonprice traits of various alternatives." (108 FERC 61,081, p.27-29)

The Commission's only recent experience with an IE was in the SDG&E Grid Reliability RFP process. SDG&E retained "an independent third party, Dr. Boothe, to observe the bid evaluation and selection process to ensure that Palomar¹⁰⁹ was not given special treatment" (D.04-06-011, p.48). Dr. Boothe's primary purpose was to ensure that "all competitors were treated fairly" (Id., p.52). Neither the Commission, nor the IE found that any unfair advantage was conferred to the affiliate bidder. The Commission did not formally evaluate the role of the IE in this RFP process.

Relative to the SDG&E Grid Reliability RFP process, Calpine recommends that an IE play a more significant and active role in any resource solicitation involving an IOU affiliate, IOU-built or IOU-turnkey bids. Calpine envisions that "an IE would be responsible for both independently evaluating the fairness of the IOUs' evaluation process and conducting its own evaluation of which resources are the least cost/best fit for ratepayers." Calpine contends that this is "something the current PRGs do not do." In instances where the IE disagrees with an IOU's resource decisions, the IE would provide the Commission with an independent recommendation as to the least cost/best fit resources from the solicitation" (Calpine Reply Brief, p.18).

In the present case, "the IOUs believe that the Commission should not require the participation of an IE in resource solicitations that may involve an IOU-owned project (whether IOU-built or turnkey) or where an IOU affiliate participates in the process. Specifically, the IOUs believe the current procurement review groups ("PRG") provide sufficient independent review of IOU procurement decisions and that there is no reason to change the current structure" (Calpine Reply Brief, p.18).

According to WPTF, "a structure must be established that puts procurement via contract on an equal footing with utility-build options [and the PRG] process does not rise to the level of an independent evaluator" (Opening Brief, p.17-18). WPTF further contends that a "level playing field ... will result in the least-cost option for ratepayers [which] can be addressed by the Commission adopting clear criteria for evaluation of bids and mandating the use of a third party independent evaluator when a utility-build project or a utility affiliate is a participant in the RFP" (Id., p.18).

No party recommends the use of an IE in all resource solicitations. Certain non-IOU parties (Calpine, IEP, and WPTF) only recommend the use of an IE in resource solicitations involving an IOU affiliate, IOU-built, or IOU-turnkey, while the remaining non-IOU parties do not offer specific positions on this issue. In contrast, the IOUs state that the Commission should not require the use of IEs in any resource solicitations, and that IEs cannot, and should not, be delegated any authority to make binding decisions on behalf of the utilities.

SDG&E, for example, supports the IE process in concept (Opening Brief, p.102) but contends that the PRG already performs this function. However, SDG&E observes that there might be situations in which a third party IE would serve a "useful purpose" (Id, p.104), but that the "utility should be left to exercise its discretion to incorporate such a feature as needed into its bid evaluation process." SCE noted that an IE procurement feature was not adopted in D.04-01-050 (p.64). PG&E also opposes an IE requirement, citing the same language in D.04-01-050. In that decision, we stated that the PRG served as one safeguard in the PPA vs. utility-owned procurement process. However, we did not preclude the adoption of additional safeguards, as necessary: "Based on our continuing review of the RFP process, we will adopt additional safeguards if we find it is necessary" (Id., p.64). We acknowledge the detailed IE guidelines set forth by FERC in its recent July 2004 and generally endorse them. At this time, we will outline an interim approach, which we may refine at a later date based on our further experience in this area. We determine here that we will not allow the IEs to make binding decisions on behalf of the utilities. We will require the use of an IE in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders. However, we will not require that the IEs administer the entire RFO process. The IOU shall consult with its IE and PRG on the design, administration, and evaluation aspects of the RFO to ensure that the overall scope is not unnecessarily broad or otherwise too narrow. IEs should be available to testify as an expert witness in any associated Commission proceeding regarding upfront review of potential solicitation transactions.

IEs should come equipped with technical expertise germane to evaluating resource solicitation power products. IEs should not be general observers hoping to be educated on the job. In the case of an affiliate/IOU-turn key power plant, IEs should be able to quickly scrutinize, examine, and essentially break down bids to determine whether the various cost components are reasonable as presented. IEs should be skilled in analyzing an range of power market derivatives (e.g., futures, contracts, options, swaps). IEs should be familiar with the various standard contracts and industry practices. IEs should have experience analyzing the relative merits of various types of PPAs. IEs should be able to evaluate PPAs, turn-keys, and IOU-builds on a side-by-side basis. An IE should make periodic presentations regarding their findings to the IOU and to the PRG.

The IOUs may contract directly with IEs, in consultation with their respective PRGs. The IOUs shall allow periodic oversight by the Commission's Energy Division. Alternatively, Energy Division can contract with IEs directly, but we will not require this given that this may result in unacceptable delays in the procurement process. IEs shall coordinate to a reasonable degree with assigned Energy Division management and staff as a check on the process.

With regard to consultants that assume the role of an IE, they shall abide by clear conflict of interest standards. We note that FERC has provided guidance on this issue. We would like to require that consultants abide by the appropriate Fair Political Practices Commission guidelines, in order to avoid the types of conflict of interest problems encountered by consultants working on behalf of the State of California and DWR during the 2000-2001 energy crisis. We must ensure the integrity of the third party evaluator process to provide firm assurances to the power market. We are open to comment from parties on specific conflict of interest standards.

G. Parties' Positions

PG&E proposes to conduct 2 parallel solicitations, one to obtain LT PPAs and another to obtain "turnkey" utility generation. For this round of solicitations PG&E will not accept bids from utility affiliates or subsidiaries. PG&E opines that by conducting separate solicitations for PPAs and utility-owned generation, the impact of debt equivalence becomes irrelevant to the choice between 3^rd party and IOU-owned generation, except as between competing PPAs¹¹⁰.

SCE agrees with the concept of a hybrid market structure provided through both a competitive market and utility-owned generators as established in D.04-01-050, but also argues that the same decision rejects the concept of evaluating IOU-owned and PPA resources in the same RFO. Utility-owned projects, with significantly different benefits, should not be compared against contracts in an RFP. An RFO is appropriate for non-utility owned generation resources and a CPCN application is the established procedure for comparison of utility-owned projects with alternatives.¹¹¹

SDG&E is of the opinion that it is neither necessary nor desirable to adopt a mechanism for comparing PPAs to utility ownership. While there are techniques for structuring an evaluation process that puts these differing options on a common basis, it is a very complex process. It is preferable to conduct this analysis on an RFP-specific basis to ensure that each project's unique circumstances and attributes are captured. The Commission should not attempt to predetermine specific bid evaluation methodologies for future solicitations

While TURN supports the Commissions preference for a hybrid wholesale electric market consisting of PPAs and IOU owned resources, the Commission should not focus on comparing the value of PPAs to IOU-owned projects. The Commission should adopt the principle that the IOUs will acquire the resources that provide the lowest net cost to ratepayers, regardless of ownership form¹¹². ORA's concerns center around balancing Commission and legislature policy for favoring certain resources and a hybrid market against the costs of different proposals when making comparisons of competing choices.

Calpine, as a potential bidder of non-utility owned PPA projects favors a transparent competitive solicitation to ensure that IOU-owned resources are not chosen by the utility over 3^rd party PPA. Calpine is concerned that because IOU-owned resources generate earnings for the utility, there is an inherent incentive for IOUs to favor IOU-owned resources over 3^rd party PPAs. In addition, because traditional cost-of-service ratemaking allows IOUs to pass the cost overruns associated with an IOU-owned resource onto the ratepayers, IOUs can favor IOU-owned resources in the bid evaluation process by submitting low bid prices with the expectation that they will be able to recover cost over runs.

Lastly, Calpine argues that the fundamental difference in the allocation of risk and the certainty of bid prices between IOU-owned projects and PPAs allows IOUs to unfairly advantage IOU-owned projects vis-à-vis PPAs in the bid evaluation. To correct the unlevel playing field, Calpine proposes that the IOUs should not be allowed to recover costs in excess of its final bid price. ¹¹³

While the Commissions has stated a preference for a hybrid wholesale electric market consisting of PPAs and IOU owned resources¹¹⁴, this should not undermine the Commission's goal of having the IOUs acquire supply-side resources based on LCBF principles, regardless of ownership form. We agree with Calpine that PPAs and utility-owned resources need to participate in the same all-source open solicitations to ensure LCBF, not in separate PPA and utility-owned specific solicitations as proposed by PG&E.

We are not persuaded by SCE's argument that D.04-01-050 precludes the IOUs from doing an all-source open RFO because a bid evaluation methodology doesn't exist. The IOUs will employ the LCBF methodology when evaluating PPAs and utility-owned bids in an all-source open RFO, taking into account the qualitative and quantitative¹¹⁵ attributes associated with each bid. The IOUs will also need to add GHG adders, as discussed in this decision, to all fossil bids. In addition, when seeking Commission approval for the proposed contracts the IOUs will need to demonstrate that they employed LCBF principles. It is expected that the Commission will revisit the LCBF methodology, integrating "lessons learned" from future all-source open RFOs.

Regarding capping cost overruns associated with utility-owned resources, we agree with Calpine that, "Putting shareholders - not ratepayers - at risk for cost overruns will put IOU-owned projects and PPAs on equal footing (at least with respect to the allocation of risk), impose some measure of market discipline on IOUs when formulating their bids, and better ensure that the resource solicitation process is fair and competitive¹¹⁶." Consequently, IOUs will not be allowed to recover costs in excess of its final bid price for utility-owned resources.

1. Debt Equivalency (DE)

Debt equivalence, the term used by credit rating agencies, specifically Standard & Poor (S&P) and to a lesser extent Moody's, to describe the fixed financial obligations resulting from long-term purchased power agreements, allegedly has significant effects on utilities' credit quality and costs of borrowing. As Edison's financial witness testified, "in determining a utility's credit rating, rating agencies pay particular attention to the company's cash flow, including its sources and uses of funds. Of particular concern are obligations that place a call on available cash, reducing a company's ability to make ongoing interest payments or to repay principal."¹¹⁷ The credit agencies are concerned that PPA payments are fixed cash commitments that, in times of financial stress, may negatively affect bondholders.

SDG&E, SCE, and PG&E recommend that DE be adopted in procurement to ensure the resource acquisition process going forward takes into account the impact of DE on the rate of return. As SDG&E argues "[I]t is essentially undisputed that the credit analysts treat the utilities' long-term non-debt obligations, such as PPAs, as if they are in fact debt when they assess a utility's debt capacity."¹¹⁸ PG&E proposes that the impact of DE on the utilities' financial condition should be addressed in the Cost of Capital (COC) proceeding, but that in this proceeding the Commission should establish that the DE impacts of new long-term commitments may be considered in the contract selection and approval process. This will allow for full disclosure of the financial effects of contracts on the utilities and promote equal consideration of competing procurement choices.¹¹⁹ All 3 IOUs reject the idea of resource specific DE - all resources should have the same DE risk factor.

As forceful as the utilities were in their support for DE, many intervenors were just as strong in their opposition. The record from the four weeks of EH is replete with testimony and cross-examination on the subject of debt equivalency. In fact, except for the subject of QFs, no other subject received as much hearing time as DE.

UCS, for example, argued against using DE when evaluating renewable PPAs, and if the Commission does decide to adopt DE then they should use a lower the risk factor for renewable PPAs. UCS fears that if DE is used for renewable PPAs that the beneficial hedging attributes of renewables will not be properly evaluated, and the utilities may not reach their RPS targets. CCC and CAC do not want DE applied to existing QF contracts because of the beneficial properties associated with existing QFs. IEP, Calpine and WPTF all argue against considering DE in procuremnent since it is a subjective factor, one that could change over time based on an improving regulatory climate, and there is no guarantee that by considering it the credit ratings of the utilities will improve.

Lastly, while ORA urges that DE be only considered in the COC proceeding, TURN supports the use of DE in procurement - assuming it is adopted in the COC. Others just asked that the issue be resolved one way or the other now so it does not stand in the way of reliability and resource adequacy.

Consistent with our discussion and findings concerning in this decision, DE should be considered when evaluating individual PPAs bids. We will adopt a modified version of SDG&E's proposal for a methodology. Because the S&P methodology is the most well-developed, we will base our methodology on theirs. However, we agree with SDG&E and believe that the S&P risk factors are too high to be reasonable and fair to all PPAs. We find it reasonable to make some acknowledgement that DE is a factor in utility creditworthiness, but not to the degree shown in the S&P methodology. We believe the regulatory climate (a significant factor in S&P's qualitative 30% factor methodology) is improving in California. We also do not want to create an unfair burden on or a disadvantage for independent power sources over utility-owned, especially in the case of renewable resources. Weighing all of these factors, we will require the utilities to employ a methodology of using one-third of S&P's 30% risk factor, which results in a 10% risk factor being applied to all PPAs.

This methodology should be used by the utilities and/or the independent evaluator when evaluating bids in an all-source RFO. Then in the IOUs' cost of capital proceedings, the IOUs will still need to demonstrate that DE has a material impact on their credit rating, and therefore borrowing costs, on a case-by-case basis. As we gain more experience with DE evaluation in the cost of capital proceedings, we may adjust the DE methodology to be used for bid evaluation in procurement going forward to future solicitations.

2. Debt Equivalence Mechanism and use in Bid Evaluation

SDG&E's DE proposal is to adopt DE to ensure the resource acquisition process going forward takes into account the impact of DE on the rate of return. To do this, SDG&E recommends that we establish a mechanism using the S&P DE methodology but only use 65% of S&P's 30% risk factor, and apply it equally to all resources.

PG&E and SCE also want DE considered as a factor in evaluating long-term contracts, recommending that the S&P methodology be applied to individual PPA bids. PG&E goes further by proposing separate solicitations for PPAs and turn/key/utility-owned bids so that the PPAs will not be at a disadvantage, as they might in an all-source RFO.

Consistent with our discussion and findings concerning DE in this decision, DE should be considered when evaluating individual PPAs bids. In their cost of capital proceedings, the IOUs will need to demonstrate that DE has a material impact on their credit rating, and therefore their borrowing costs on a case-by-case basis.

3. Climate Change in LTPP

Consistent with established Commission policy, the positions of several parties, and the present actions of one IOU (PG&E), we adopt a range of values for a "greenhouse gas (GHG) adder" to be used in the evaluation of fossil generation bids. This range is taken from information in the present record. Each IOU will select a value within the adopted range and be prepared to respond to party comment on the value, before employing the adder in analyzing RFO responses.

The GHG value will be added to the fossil prices bid in future procurement, and will be used to develop a more accurate price comparison between fossil, renewable and demand-side bids. In the event that the fossil bid is ultimately selected, the adder will not be paid to that generator; it is an analytic tool only.

In addition to the GHG adder, the IOUs are directed to employ, when finalized and approved by the Commission, the externality values under development in the Avoided Cost Rulemaking (R.04-04-025). It is anticipated that these values will be adopted in approximately March 2005, and will include a fixed value for GHG (not simply a range) as well as values for other, non-GHG pollutants. These values should be appropriately added to any fossil bids the IOUs receive in response to an RFO. It is anticipated that the Commission will adopt these values in a decision in R.04-04-025 before the IOUs undertake any procurement as a result of this decision. Therefore, all procurement undertaken subsequent to this decision should employ the GHG adder adopted in this decision, until replaced with a decision in R.04-04-025, when analyzing bids.

Finally, Commission staff is directed to prepare a report analyzing the potential structure and merits of an IOU portfolio-wide "carbon cap" as an efficient means of minimizing utility contributions to climate change. This report should be prepared for Commission consideration in 2005.

H. Background

At the time of the issuance of this decision it is still not known if carbon regulation, in the form of emissions limits, will be instituted in the timeframe of the LTPPs. However, California, and in particular this Commission, along with the CEC and CPA, have given clear signals that they want to be the pacesetters in this arena and take positive steps in seeing action on this front. Beginning in May 2003 with the issuance of the EAP, the state and this Commission committed to making inroads to preserving the environment with the following:

"The state needs to guide development of the energy system in the public's best long-term interest, to anticipate potential problems, and to make timely decisions to resolve problems. Specifically, the agencies commit to:

1. Make continuing progress in meeting the state's environmental goals and standards, including minimizing the energy sector's impact on climate change."

Following on the heels of the EAP, the Commission noted in D.04-01-050 that we were:

"Presently working with a contractor in R.01-08-028 for the explicit purpose of reviewing and updating its avoided-cost methodology for analyzing the costs and benefits of various resource options....In this decision, we refer the question of potential financial risks associated with carbon dioxide emissions to R.01-10-028, to be considered in the context of updates to the avoided costs methodology - as part of the overall question of valuing the environmental benefits and risks associated with utility current or future investments in generation plants that pose future financial regulatory risk of this type to customers." ¹²⁰

R.04-04-025 is the successor rulemaking to R.01-08-028 for purposes of addressing environmental issues in the context of generation investments.

The Commission then issued this proceeding, R.04-04-003, with Appendix "B" that set forth the "SkyTrust" type Cap-and-Trade Incentive Framework as follows:

"In terms of specific pollutants, of significant concern to regulators and the public today is the environmental damage caused by carbon dioxide (CO₂) emissions-an inescapable byproduct of fossil fuel burning and by far the major contributor to greenhouse gases. Unlike other significant pollutants from power production, CO₂ is currently an unpriced externality in the energy market.... CO₂ is not consistently regulated at either the Federal or State levels and is not embedded in energy prices.... California needs a framework for procurement incentives that recognizes the importance of reducing California's dependence on fossil fuels-for a variety of environmental, security, and price volatility reasons." ¹²¹

On June 29, 2004, ALJ Wetzell issued a ruling in this proceeding, R.04-04-003, presenting questions for the IOUs to answer and address in their LTPPs regarding climate:

"San Diego Gas & Electric Company, Southern California Edison Company, and Pacific Gas and Electric Company shall address the following questions pertaining to climate change in their long-term plan filings:

1. Describe the utility's position regarding the extent of the threat posed by climate change, and the contribution of electricity generation to that threat.

2. Describe any internal planning or measurement activities currently being undertaken to evaluate and address the threat of climate change, both generally and as a result of utility operations, including URG and power purchased under contract.

3. Describe, to the fullest extent possible, the utility's emissions profile with respect to the six criteria greenhouse gases: carbon dioxide (CO2); methane (CH4); nitrous oxide (N2O); hydrofluorocarbons (HFCs); perfluorocarbons (PFCs); and sulfur hexafluoride (SF6). Include both URG and power purchased under contract.

4. Describe any steps the utility has taken to minimize the release of these gases as a result of utility operations, and how your Procurement Plan advances this effort.

5. Describe the utility's position regarding the optimal policy response to the threat of climate change, and how your Procurement Plan is aligned with this policy response."

i. In their LTPPs the IOUs offered a range of responses to these questions, from more concerned with climate (PG&E) to less so (SCE). None provide the profile requested, as they are all moving through the Climate Action Registry's inventory and auditing process now.

In its post-hearing brief PG&E indicated that it plans to value carbon risk with "reputable" price data¹²² - and proposes using $8/ton, consistent with the data in the now final E3 Report on Avoided Cost.¹²³

SCE stated that it planned to incorporate CEC and EPA in future climate strategizing.¹²⁴

NRDC proposes that the Commission direct the IOUs to financially impute a $/ton CO2 value into the analysis of all fossil bids; require the IOUs to include in their next LTPPs the emissions profiles compiled by CA Climate Action Registry; and that the IOUs must "develop and implement a comprehensive GHG reduction plan" via their next LTPPs. We find these suggestions consistent with the EAP and other Commission statements. UCS urges the Commission to require the IOUs to model carbon costs in future LTP plan preparation; to consider these costs, but not price them, in present resource solicitations; and to utilize PG&E's experience from this proceeding in educating parties and the IOUs for future LTPPs. TURN advocates the adoption of a carbon adder taken from the analysis in AC Rulemaking, R.04-04-025; the development of a policy to have bidders submit prices that include and exclude carbon regulation risk and a requirement that market sentiment on carbon prices be divulged.

I. Range of values for the GHG Adder

Utilizing data from the record in this proceeding (not doing this now), following is a range of values for the GHG adder:

a. Final E3 Avoided Cost Report - $5/ton C02 today

$12.50 by 2008

$17.50 by 2013

b. PG&E internal RFO review - $8

c. PacifiCorp 2003 IRP - $8

d. NRDC opening brief - $12 beginning 2008

e. Idaho Power Co IRP - $12.30 beginning 2008

f. EIA analysis of proposed legislation¹²⁵ - $15-$25 in 2010

$14-$36 in 2020

Consistent with established Commission policy, the positions of several parties, including PG&E, we adopt a range of values for a "greenhouse gas (GHG) adder," of $ 8 to $25 per ton, to be used in the evaluation of fossil generation bids. This range is taken from information in the present record. Each IOU will select a value within the adopted range and be prepared to respond to party comment on the value, before employing the adder in analyzing RFO responses.

The GHG value will be added to the fossil prices bid in future RFOs, and will be used to develop a more accurate price comparison between fossil, renewable and demand-side bids. In the event that the fossil bid is ultimately selected, the adder will not be paid to that generator; it is an analytic tool only.

In addition to the GHG adder, the IOUs are directed to employ, when finalized and approved by the Commission, the externality values under development in the Avoided Cost Rulemaking (R.04-04-025). It is anticipated that these values will be adopted in approximately March 2005, and will include a fixed value for GHG (not simply a range) as well as values for other, non-GHG pollutants. Other GHGs, in addition to carbon, will also be included. These values should be added to any fossil bids the IOUs receive in response to an RFO. It is anticipated that the Commission will adopt these values in a decision in R.04-04-025 before the IOUs undertake any procurement as a result of this decision. Therefore, all procurement authorized subsequent to this decision should employ the GHG adder adopted in this decision, until replaced with a decision in R.04-04-025, when analyzing bids.

J. DWR contract allocation and reallocation (Sunrise)

The June 4, 2004, ACR/Scoping Memo provided the IOUs with conventions for DWR contract allocation and reallocation to be used in their modeling. The ACR asked the utilities to assume that the new DWR contracts, Kings River and CCS, be allocated to PG&E as proposed by DWR, and Sunrise allocation remain as is with SDG&E.

PG&E presented no DWR issue in this proceeding. SDG&E, although its position is that the DWR Sunrise contract should be reallocated to PG&E, conformed with the directions from the ACR and included Sunrise in its resource portfolio. SCE had no issue concerning DWR contracts for this proceeding.

There is another proceeding, A.00-11-035, that is addressing the subject of cost allocation of DWR contracts. Therefore, except for including DWR contracts in the utilities' resource portfolios, there is no DWR contract issue.

Therefore the arguments presented by SDG&E that keeping Sunrise in its plan reduces its option to address local reliability issues because Sunrise is outside the territory, provides no benefit to local reliability and leaves the utility with no "headroom" to add a local resource till the contract expires in 2010, and ORA's proposal that SCE contract with SDG&E for dispatch rights for specific units under the DWR-Williams contract, will be addressed either in the next phase of RA, or in the DWR contract proceeding.

DWR requests that this decision clearly state that nothing in this decision makes changes to prior Commission decisions, particularly D.02-12-074, the
IOU-DWR Servicing Agreements, or makes any changes in ratemaking treatment of the DWR contracts. We think DWR's request is reasonable and we adopt it until further Commission action on the subject.

1. Repowering:

WCP refers collectively to the limited liability companies that own and operate approximately 2,300 MW in Southern California. The facilities, Encina power plant, combustion turbines in the San Diego area, the El Segundo power plant and the Long Beach power plant are extant power plants that are often referred to as "aging" power plants. WCP urges the Commission to recognize the crucial role of these aging power plants in the electric system and recommend the Commission recognize and respond to the threat of aging power plants retiring before they can be replaced with new capacity. WCP suggests the following:

Short term: Continue to use RMR contracts

Mid term: The Commission must ensure that the IOUs enter into multi-year local reliability contracts with power plants in key locations. This would include contracts with three to five year terms, directing the IOUs to revise their resource plans to show how congestion and local reliability are considered in their procurement decisions. SDG&E should be required to conduct a comparison between the overall cost of its proposed new 500 kV line and the costs of new generation resources located at the site of existing generation in its service area, and to apply RA principles to load pockets.

Long term: The Commission should recognize the benefits of siting new generation at the existing sites of aging power plants and adopt a policy to promote construction of new generation units at brownfield sites rather than green field sites.

WPC also urges the Commission to establish a capacity market.

SCE disagrees with WCP's position that brownfield sites should receive priority over other options. SCE points that WCP's position is self-serving and that majority of parties, including ORA agree with SCE. SCE argues that the benefits of brownfield sites such as proximity of existing sites to the load center, access to transmission lines and natural gas infrastructure, possession of permits required for operation, possession of rights to water and others are already accounted in SCE' selection of best fit/least cost resources. SCE notes that these advantages benefit the developer by substantially reducing the cost of the project and increasing the competitiveness of the brownfield over the greenfield sites. In SCE's opinion these plants should not be favored over new generation if they cannot compete cost-effectively with new generation.

Instead, SCE suggests that these aging power plants enter into RMR contracts, which limit the market power of such plants, sell into the spot market, or enter into short term contracts. SCE also notes the risk of entering into contracts with sub-investment grade companies such as Dynegy or NRG (WCP's owner). SCE argues that the least cost/best fit as the overarching principle of procurement for providing the best value to its customers.

Dynegy advocates continued availability of existing capacity pending implementation of RA, CAIS market design and the creation of a supporting capacity market structure.

K. Long-Term Planning in the Next Procurement Cycle

D.04-01-050 determined that in future cycles of the procurement process, we would link our timing to that of the CEC's Integrated Energy Policy Report. Since that proceeding operates on a biennial calendar, by stature, that means that the next long-term procurement proceeding will be in 2006. D.04-01-050 also linked the substance of the analyses we direct IOUs to file with the results of the CEC's IEPR information and analyses. In the past two years, the CEC and this Commission are collaborating to a much greater degree than ever before, and as evidence the CEC is not a party to this proceeding and its staff is assisting our own in review of IOU LTPPs and in developing resource adequacy procedures.

On September 16, 2004, President Peevey issued an Assigned Commissioner Ruling addressing further integration between the CEC's IEPR and our next procurement proceeding. That ACR suggested a specific type of coordination between the 2005 IEPR and the 2006 procurement proceeding. In essence, the CEC's IEPR would review IOU load forecasts, conduct a resource assessment and identify the range of need for new resource additions addressing significant uncertainties for each IOU. Our 2006 procurement proceeding would not relitigate those results, except in those cases where there is new information that was not available to be considered in the CEC's proceeding, and our 2006 procurement proceeding would address IOU resource procurement proposals and strategies in light of the range of need identified in the 2005 IEPR. We will also consider how CEC statewide policy recommendations may be translated into IOU-specific directives, given the circumstances of each IOU. A more specific enumeration of proposed relationships between this Commission, the CEC, and the CAISO is attached as Appendix B.

We endorse the coordination agreement and the direction to IOUs stated in the September 16, 2004 ACR. We direct IOUs to participate in the CEC IEPR proceeding as the one forum in which long-term load forecasts, resource assessments, and need determinations will be considered. We believe Appendix A constitutes a good foundation for coordinated proceedings and the minimization of duplication between various planning proceedings. We direct staff to work with the CEC and CAISO to effectuate this agreement in a complete and practical manner.

Commission provide equivalent assurance for cost recovery of turnkey projects as it had for other procurement resources.

In the LTPP proceeding SDG&E proposes a three-phase cost recovery framework for turnkey project cost recovery that starts with the filing for Commission approval of the project. In that filing, SDG&E will identify the rate-base and O&M-related revenue requirements associated with the project for the first full calendar year of operation of the generation plant. SDG&E proposed to record costs associate with the turnkey plants to its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) for recovery through SDG&E commodity rates. Under SDG&E's proposal, the Commission will adopt the annual revenue requirement of the applicable turnkey plant simultaneously with approval of the project. Prior to the operation of the turnkey generation unit, SDG&E will file an advice letter to incorporate any adjustments to the adopted revenue requirement.

The second phase of the framework covers the period from the end of the initial phase until the implementation of SDG&E's next Cost of Service (COS) decision to allow for annual attrition adjustments to the authorized revenue requirement.

The third phase, SDG&E's revenue will be trued up to reflect the costs of these projects.

PG&E requests that the Commission provide timely cost recovery of utility owned generation when the facility starts serving utility customers, whether PG&E operates the plant itself or when it contracts with a third party to operate it. Under PG&E's proposal, PG&E would include the initial capital cost of the acquisition in its request for approval of the contract.

UCAN opposes SDG&E's proposal for cost recovery and argues that the Commission sets revenue requirements in the General Rate Case (GRC) and should not allocate separate revenue requirements for each asset owned by the utility in a non-GRC proceeding.

We find SDG&E's mechanism reasonable and adopt it for all three IOUs. In the next few years, IOUs could add extensive new generation to their resource portfolios in order to meet their future resource needs. We believe a rate making mechanism needs to be in place to ensure proper and timely cost recovery for these facilities. Two issues need to be decided; the timing and the scope of the cost recovery. First, we determine the appropriate timing of the rate recovery. Both SDG&E and PG&E propose to start cost recovery when the new facility starts operation to serve utility customers. We agree and adopt this proposal.

Second, we adopt SDG&E's proposal for cost recovery. SDG&E proposes to establish rate-base and O&M-related revenue requirements associated with the generation plant and to use its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) to record costs associate with the turnkey plants and for recovery through SDG&E commodity rates. PG&E, however, proposes differently. In addition to the costs listed above, PG&E proposes that in some cases, it may be necessary to request recovery for "financial burden associated with acquisition of utility-owned generation."¹²⁶ In PG&E's opinion, these costs may include planning and administrative costs of preparing for the construction or acquisition of the generation facilities, financing costs as incurred, and costs if the project is ultimately abandoned. We believe that some of these costs or risks will be considered in our review and evaluation of IOU contracts for turnkey projects and some will be considered as part of establishing the revenue requirement for these facilities. For example, we expect contracts for turn key projects address provisions and penalties for project abandonment. As such these types of costs should not receive special recovery treatment. We reject PG&E's proposal in this respect.

L. Other Procurement Issues

1. Resource Adequacy Issues Not Addressed in the Resource Adequacy Decision

As briefly discussed in Section A.2, the RA decision, D.04-10-035, accelerated the target date to June 1, 2006, for the IOUs to acquire their reserve margins of 15-17% as established in D.04-01-050. Comments on the PD in the RA decision were circulating concurrently with the post-hearing briefs in the LTPP portion of this proceeding. Numerous parties raised the same issues in the post-hearing briefs as well as in their comments to the RA PD. In particular, parties weighed in on the creation of a multi-year forward commitment obligation. This topic is clearly specific to the RA decision since it is related to the design features of that program and it is appropriate to visit it in Phase II of RA.

Another area of possible policy conflict between RA and procurement is the treatment of resource acquisitions over 17%. D.04-01-050 established the reserve margin requirement of 15-17%, and D.04-10-035 accelerates the due date, but does not change the 15-17%. Some parties interpret the RA range to mean that 15% is desirable and up to 17% can be acceptable temporarily due to lumpiness issues. Others view 16%, the average of 15-17%, as being the target. Still others argue that only acquisitions over 17% should raise any issue of penalties or disapproval. Since the RA phase is designed to handle the reserve margin issues we will not rewrite D.04-01-050 in this decision. If parties want further clarification on the interpretation of the 15-17% requirement they should bring it up in Phase II of the RA portion of this docket. This LTPP decision is not intended to change or modify any aspect of D.04-10-035. Any clarifications, alterations or augmentations to D.04-10-035 will be deferred to Phase II of the RA aspect and not addressed here.

2. Local Reliability as Part of the Procurement Process

D.04-07-028, issued in July 2004, established temporary local reliability requirements. Parties presented a full spectrum of viewpoints on this topic in their post-hearing briefs from deferring procurement until requirements are actually established, to wanting the IOUs to procure now. While we expect RA Phase II to resolve local reliability issues, in the interim we extend the requirements of D.04-07-028. In particular, the policy requirements of D.04-07-028 and any implementation procedures should be handled by IOUs filing Advice Letters until local reliability is resolved in RA Phase II, or by other action of this Commission.

SDG&E is a unique case among the three IOUs in that within service area resource additions almost certainly will provide local reliability benefits, unlike SCE or PG&E. We therefore direct SDG&E to pursue the EAP loading order priorities when it makes resource additions.

3. Bottom-up Planning

Prior to the restructuring of the electric utility industry in California, the utilities were actively involved in integrated resource planning. With the passage of AB1890 and the restructuring of the industry, the utilities moved away from active involvement in resource planning and became merchants of power on behalf of their customers. Since the California energy crisis, the pendulum has begun to move back in the other direction again. The utilities are more actively involved in developing as well as contracting for the resources required to serve their customers. Naturally, this has led to renewed interest in making sure that the choices reflect the best trade-offs among the uses of society's limited resources.

In the January Policy Decision (D.04-01-050) we stated that by relying on a bottom-up approach to system planning, "[t]he Commission and utilities would be able to ensure that state policies are implemented in a manner designed to contain cost while achieving other goals. Such a process is not merely consistent with the state's broader policy goals - it will help sustain them."¹²⁷ That decision discussed integrated resource planning to provide a comprehensive context for all of a utility's resource decisions. The Assigned Commissioner's Ruling and Scoping Memo in the current proceeding requested that the topic of bottom-up planning be included in the utilities' long-term plans.¹²⁸ All three utilities included discussions of bottom-up planning in their long-term plans as requested.

PG&E notes that it has followed the Commission's direction regarding planning, including following the Loading Order, which was developed since the last long-term plans were filed. PG&E states in its LT procurement plan that it has integrated the results of the CAISO-sponsored annual Assessment Studies and Electric Transmission Expansion Plan process into its integrated resource planning. The LT plan describes the processes underlying its adoption. PG&E will compare the most promising identified generation or demand response alternatives with the Commission-approved plan, and it will examine the planning level costs of all transmission, generation, and demand response alternatives. PG&E asserts that its account services representatives have historically looked at the individual needs of customers, practicing local planning at the lowest level, and will do so even more in the future as the Company acquires an increased portfolio of energy efficiency, demand response, and distributed generation resources.

SCE's LT procurement plan described the annual planning process it uses to identify projects necessary to serve new load added to the Company's transmission and distribution system. Edison begins with development of 10-year peak-load forecasts for each substation in the SCE distribution system. They are developed using a bottom-up approach which takes advantage of the Company's regional engineers' knowledge of the local areas. Those substation-level forecasts are then compared to, and reconciled with, system demand forecasts developed using a top-down approach. Identification of system requirements requires technical studies performed as part of the load-growth planning process, which determines whether expected growth can be accommodated through the existing distribution system, or what kinds of projects are required to bring the system back to within specified loading limits. Development and evaluation of alternatives identifies alternatives for correcting any projected system deficiency. Finally, selection, approval and budgeting results in identification of the best combination of system performance, reliability, operational flexibility, and cost to select a preferred plan from among the alternatives.

SDG&E states that because its entire service territory constitutes a single load pocket, the solutions offered for the service territory in total are identical to those envisioned by the Commission in its discussion of bottom-up planning. SDG&E has been an active participant in numerous regional planning and energy policy forums, as well as discussions with customers and other stakeholders, and has used any gained insights in its planning process. This approach includes, but is not limited to, working with the City of San Diego to assist in meeting the goal of installing 50 MW of renewable resources by 2013 and finding ways to promote further development of, and explore possible future sites for, solar facilities in the San Diego region.

The three utilities have presented information on the processes they undertake to develop bottom-up forecasts of their needs and of the plans to deal with those needs. We are satisfied that the utilities are seriously following our direction and taking into account the needs of local areas within their service areas in developing their plans.

4. Long-Term Planning in the Next Procurement Cycle

Commission provide equivalent assurance for cost recovery of turnkey projects as it had for other procurement resources.

The third phase, SDG&E's revenue will be trued up to reflect the costs of these projects.

Second, we adopt SDG&E's proposal for cost recovery. SDG&E proposes to establish rate-base and O&M-related revenue requirements associated with the generation plant and to use its Non-Fuel Generation Balancing Account (NGBA) and Energy Resource Recovery Account (EERA) to record costs associate with the turnkey plants and for recovery through SDG&E commodity rates. PG&E, however, proposes differently. In addition to the costs listed above, PG&E proposes that in some cases, it may be necessary to request recovery for "financial burden associated with acquisition of utility-owned generation."¹²⁹ In PG&E's opinion, these costs may include planning and administrative costs of preparing for the construction or acquisition of the generation facilities, financing costs as incurred, and costs if the project is ultimately abandoned. We believe that some of these costs or risks will be considered in our review and evaluation of IOU contracts for turnkey projects and some will be considered as part of establishing the revenue requirement for these facilities. For example, we expect contracts for turn key projects address provisions and penalties for project abandonment. As such these types of costs should not receive special recovery treatment. We reject PG&E's proposal in this respect.

5. Utility filings demonstrating compliance

In prior Commission decisions issued in R.01-01-024, we established the following filing requirements:

Filing

Decision

Function

Monthly ERRA Report

D.02-12-074 (OP 19)

Shows the activity in the ERRA balancing account with copies of original source documents supporting each entry over $100.00 recorded in the account.

Monthly Portfolio Risk Report

D.03-12-062 (OP 2 and 4)

Informs the Energy Division on the risk exposure of the IOU's procurement portfolio.

Quarterly Transaction Report

D.02-10-062 (OP 8)

Tracks procurement transactions and shows that they comply with the approved procurement plan.

Semiannual ERRA Application

D.02-10-062

D.02-12-074

D.04-01-050

Sets electric energy procurement forecast rate.

Enacts trigger, if met.

Reviews contract administration and least-cost dispatch.

Short-Term Procurement Plan (STPP)

D.02-12-074

D.03-12-062

Addresses the procurement products, processes, risk management strategy and tools

Gas Supply Plan (GSP)

D.03-04-029 (OP 6)

Long-Term Procurement Plan

D.04-01-050

PG&E requests that the Commission streamline the review of procurement costs through quarterly transaction reports and ERRA proceedings. PG&E states that "by expediting the process for verifying that utility transactions are consistent with adopted procurement plans, the Commission can confirm the transactions are in compliance and eliminate any second-guessing during ERRA compliance reviews. The Commission should require that the reviews be completed on time and the scope should be limited to review of the transaction identified by the independent auditor."

PG&E proposes the following: (1) Issue an omnibus resolution approving all unprotected, unresolved, quarterly procurement transaction advice letters as submitted, and (2) focus on truing up forecasted expenses to actuals in the ERRA compliance review proceeding and review the tractions identified in the quarterly transaction review process that are noncompliant with the procurement plan.

SDG&E recommends that the semiannual Gas Supply Plans be consolidated into the ERRA/STPP process, "as gas is an integral part of least-cost dispatch and short-term procurement planning and consolidation would eliminate redundancy, thus easing the resource constraints for both the Commission and SDG&E." (McClenehan Opening Testimony, p.12) Furthermore, SDG&E proposes that advice letter updates to the forecasts contained in the plan be filed in conjunction with each utility's ERRA forecast and that authorization would be for a rolling five years. SDG&E also recommends that gas supply plans be consolidated into the ERRA/short term procurement plan process.

SCE suggests that the AB 57 plans need not be updated on an annual basis, and not in the ERRA proceeding. Instead, AB57 can be updated as needed, e.g. if there were changes in the LTPP that required it.

DWR opposes SDG&E's recommendation that the Commission consolidate the review and approval of gas supply plans into the ERRA proceedings, stating that the recommendation is not consistent with the contractual obligations of SDG&E under its current Operating Agreement with DWR. (Memo, p.3)

ORA recommends annual reviews of procurement plans in ERRA proceedings.

We continue the Monthly ERRA Report and Monthly Portfolio Risk Report. In regards to the Quarterly Transaction Report, the IOUs are ordered to file a joint proposal to reformat the report in a way that will provide the Commission concise and coherent information, thereby streamlining the review process. The objective of the report is to show that the transactions entered into are in compliance with the upfront standards identified by the Commission. These reports will be reviewed by the ED staff. If there are no protests and the staff concludes that the transaction entered into in that quarter comply with the utility's procurement plan, then by the Commission's Expressed Delegation of Authority, the ED Director can approve the reports. However, if there are substantive protests and the staff takes issue with certain transactions, the staff will issue a draft resolution for the Commission's approval.

We find that no change is necessary at this time for the Semiannual ERRA Application. As for the Short-Term Procurement Plan, the 2006 Long-Term Procurement Plans will contain the features of the Short-Term Plans that are not covered by the proposed 2004 LTPPs. That is, ultimately, we will eliminate the STPPs and the IOUs will act in accordance with a single Commission-approved plan. Until then, the existing STPPs will be in effect. Updates or modifications to the plans in between the biennial review will be filed with an advice letter. Any updates to the existing STPPs should be filed with an Advice Letter 30 days after the issuance of this decision.

In regards to the Gas Supply Plans and the biennial LTPPs, we find no change is necessary at this time.

M. Collateral Requirements

As part of its regular operation in a hybrid energy market, SCE periodically contracts with numerous counterparties for various electric and natural gas products. Counterparties require SCE to post collateral in the form of "cash or letters of credit if their exposure to SCE exceeds a predetermined negotiated limit (the Unsecured Credit Limit). According to SCE's long-term plan:

"The requirement to provide collateral stems from a contracting counterparty's concerns that SCE will be unable to meet its obligations under the contract. These counterparties may be either physical buyers of SCE's excess energy or sellers of energy, capacity, or natural gas to SCE. SCE may also enter into financial transactions which act to hedge ratepayers' exposure to future market price movements.¹³⁰ In each case, the transaction counterparties will attempt to minimize their risk by requiring SCE to post cash or letters of credit if their exposure to SCE exceeds a predetermined negotiated limit (the Unsecured Credit Limit)." (SCE Long-Term Plan, Vol.1, July 9, 2004, p.28)

SCE states that its currently "authorized procurement plan includes sufficient collateral capacity for the near term. However, SCE's ability to stay within the current Commission authorized collateral limit will depend heavily upon the length of new contracts signed to meet resource needs" (Id., p.31). SCE has stated its intent "to file an update to its STPP procurement plan within 30 days of the Commission's long-term procurement decision to conform it to Commission policies. If an increase to SCE's collateral capacity is required to carry out the revised plan, SCE will provide updated collateral estimates as part of this filing" (Opening Brief, p.131). No party has taken issue with SCE on this issue. Accordingly, we accept SCE's stated approach.

We also note here that SCE can, and does, require counterparties to make similar collateral postings aimed at ensuring contract performance under changing market conditions. Calpine asks the "Commission [to] be sensitive to the fact that credit requirements can be used to either (i) squelch competition through onerous credit requirements; or (ii) to impose on ratepayers the costs associated with a zero risk tolerance" (Calpine Direct Testimony, p.18-19). Calpine warns that if "overcollateralized, project sponsors will be placed at a competitive disadvantage ... [and that these] excessive credit requirements will be passed on to ratepayers through higher prices" (Id., p.19). We are not aware of any specific claims of over-collateralization or associated recommendations.

1. New Accounting Rules

SCE has informed the Commission of two relatively new accounting rules promulgated by the Financial Accounting Standards Board (FASB) "that, like the debt equivalence issue, may affect electric utilities' costs of contracting for power" (SCE Long-Term Plan, Vol.1, July 9, 2004, p.47-50). One rule would require "utilities to include certain long-term contracts as liabilities on their balance sheets by deeming them capital leases,"¹³¹ and the other rule (FASB interpretation) "could impose additional balance sheet impacts on utilities signing long-term contracts"¹³² (Id., p.47).

According to SCE, "a capital lease requires a utility to book the plant as an asset (similar to the accounting treatment for a utility-owned plant), and to record the present value of the expected lease payments as long-term debt on its balance sheet." (Id., p.49). The second rule may require SCE "to consolidate [certain counterparties in its balance sheet] for financial reporting purposes" (Id., p.50). SCE has not requested any specific relief related to these new accounting rules.

We observe here that consideration of such accounting rules may have been more appropriate in the Cost of Capital proceeding. Since SCE contends that these new accounting rules are somewhat similar in effect to debt equivalence, SCE may seek further guidance from the Commission when appropriate in the same manner as set forth in the Cost of Capital proceeding.

⁹² The "Existing AB57 PP is the same as the "2004 Short-Term Procurement Plan - Confidential Version," dated May 15, 2003, as modified by the Commission in D.03-12-062 and submitted by SCE in Compliance Advice Letter 1770-E-A, dated February 23, 2004. These plans are also referred to at times in SCE's LTPP as the "Implementation Plan."

⁹³ D.04-01-050, mimeo at 61

⁹⁴ Calpine opening brief, p. 12.

⁹⁵ Id., pp. 11, 12.

⁹⁶ FERC Opinion and Order Affirming Initial Decision In Part, Denying Requests for Rehearing and Announcing New Guidelines for Evaluating Section 203 Affiliate Transactions, Opinion No. 473, Ameren Energy Generating Co., et al. 108 FERC ¶ 61,081 (2004).

⁹⁷ SCE opening brief, pp.88, 90.

⁹⁸ SDG&E opening brief, pp. 96-97.

⁹⁹ Sempra opening brief, pp. 3-4.

¹⁰⁰ WPTF opening brief, pp 11-13.

¹⁰¹ See Ex. 70 (Fulmer), p. 20, line 20, to p. 21, line 5.

¹⁰² As referenced by IEP in its Opening Brief, October 18, 2004, p.2, footnote 2.

¹⁰³ Qualitative and quantitative attributes such as performance risk, credit risk, price diversity (10 vs. 20 yr. price terms), and operational flexibility etc.

^[1] D. 04-01-050, Conclusion of Law 19.

¹⁰⁴ FERC Edgar Standard: "We note that there are three ways to demonstrate lack of affiliate abuse under the Edgar standard: (1) evidence of direct head-to-head competition between the affiliate and competing unaffiliated suppliers in a formal solicitation or informal negotiation process; (2) evidence of the prices which non-affiliated buyers were willing to pay for similar services from the affiliate; and (3) and benchmark evidence that shows the prices, terms and conditions of sales made by non-affiliated sellers. Because the market for generating assets is not nearly as liquid as the market for PPAs, a competitive solicitation through a formal RFP in future section 203 cases is likely to be the most effective way to show that an affiliate transaction is not marred by affiliate abuse. In the context of an acquisition of affiliated generation, a competitive solicitation is the most direct and reliable way to ensure no affiliate preference." 108 FERC 61,081 (July 29, 2004), paragraph 67.

¹⁰⁵ This is similar to our use of the Appendix A "screens" adopted in the Merger Policy Statement to quickly identify transactions that are unlikely to harm competition. Largely due to these screens, this Commission has succeeded in reducing the amount of time necessary to analyze and approve section 203 applications.

¹⁰⁶ See, e.g., Technical Conference Comments of Maine Public Utilities Commission Chairman Welch, Conference on Solicitation Processes for Electric Utilities, Docket No. PL04-6-000, (June 10, 2004) (PL04-6 Conference) at Tr. 78.

¹⁰⁷ See, e.g., Technical Conference Comments of John Hilke, Federal Trade Commission, PL04-6 Conference at Tr. 4.

¹⁰⁸ Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (2000), FERC Stats. & Regs., Regulations Preambles July 1996 - December 2000¶ 31,089 at 31,061 (1999), order on reh'g, Order No. 2000-A, 65 Fed. Reg. 12, 088 (2000), FERC Stats. & Regs., Regulations Preambles July 1996 - December 2000 ¶ 31,092 (2000), affirmed sub nom. Public Utility District No. 1 of Snohomish County, Washington, et al. v FERC, 272 F. 3d 607 (D.C. Cir. 2001).

¹⁰⁹ "SDG&E is proposing to purchase [Palomar] from SER [Sempra] a 500 MW (base load)/ 555 MW (peaking load) combined cycle natural gas-fired generation plant to be built by SER, and then turned over to SDG&E as a utility owned generation asset. This project is located in the utility's service territory on a 20-acre site in Escondido, and is expected to go on line in June 2006." (D.04-06-011, p.47)

¹¹⁰ PG&E opening briefs, pp. 60,61,64,65

¹¹¹ SCE opening brief, pp. 89, 90, 91, 92, 96.

¹¹² TURN opening brief, pp. 12

¹¹³ Calpine opening brief, pp. 10-12.

¹¹⁴ See Hybrid Market section (#?)

¹¹⁵ Qualitative and quantitative attributes such as performance risk, credit risk, price diversity (10 vs. 20 yr. price terms), and operational flexibility etc.

¹¹⁶ Calpine opening brief, pp. 12

¹¹⁷ SCE/Simpson Ex. 73, 21:2-5.

¹¹⁸ SDG&E opening brief, p. 89.

¹¹⁹ PG&E opening brief, p. 51.

¹²⁰ D.04-01-059, p. 108.

¹²¹ R.04-04-003, Appendix B, p. 5.

¹²² RT 9/7/04, p. 906: 17-20, Pulling.

¹²³ Methodology and Forecast of Long-Term Avoided Cost(s) for the Evaluation of California Energy Efficiency Programs, E3 Research Report Submitted to the CPUC Energy Division, October 25, 2004. http://www.ethree.com.

¹²⁴ SCE/Hertel, Ex. 56, p. 78.

¹²⁵ PacifiCorp, IPC and EIA estimates sited in NRDC Opening Brief, 10/18/04, p.16-17

¹²⁶ PG&E's prepared Testimony, Page 2-38.

¹²⁷ D.04-01-050, p. 97.

¹²⁸ OIR 04-03-003, Assigned Commissioner's Ruling and Scoping Memo, June 4, 2004, p. 7.

¹²⁹ PG&E's prepared Testimony, Page 2-38.

¹³⁰ While not all financial hedges will result in collateral requirements, transactions such as financial futures or swaps will result in mark-to-market exposures similar to physical contracts.

¹³¹ EITF Issue 01-08, "Determining Whether an Arrangement Contains a Lease," May 15, 2003, effective for new or revised power contracts entered into after June 30, 2003.

¹³² FASB Interpretation No. 46 (revised December 2003) "Consolidation of Variable Interest Entities-an interpretation of ARB No. 51."

Filing	Decision	Function
Monthly ERRA Report	D.02-12-074 (OP 19)	Shows the activity in the ERRA balancing account with copies of original source documents supporting each entry over $100.00 recorded in the account.
Monthly Portfolio Risk Report	D.03-12-062 (OP 2 and 4)	Informs the Energy Division on the risk exposure of the IOU's procurement portfolio.
Quarterly Transaction Report	D.02-10-062 (OP 8)	Tracks procurement transactions and shows that they comply with the approved procurement plan.
Semiannual ERRA Application	D.02-10-062 D.02-12-074 D.04-01-050	Sets electric energy procurement forecast rate. Enacts trigger, if met. Reviews contract administration and least-cost dispatch.
Short-Term Procurement Plan (STPP)	D.02-12-074 D.03-12-062	Addresses the procurement products, processes, risk management strategy and tools
Gas Supply Plan (GSP)	D.03-04-029 (OP 6)
Long-Term Procurement Plan	D.04-01-050