VIII. 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 supported 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 GHG 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, and deliver California's energy services according to the priorities of state policy.

A. Proposals Regarding Open And Transparent Competitive Bidding Process

All parties addressing the topic of a competitive bidding process favor an open and transparent process. However, as PG&E and SCE contend, for many parties, especially those in competition with the IOUs, that means that the parties should have more access to confidential utility information. For others, open and transparent means a fair bidding and bid evaluation process.

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 04-01-050.98 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."99 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, SONGSs, 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"100

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 aan independent third party evaluator, as set forth in The FERC's competitive solicitation guidelines101 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."102

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. However, tThe 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."103 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."104

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.105

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.106

1. 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 turnkey 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,107 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)

2. Requirements for 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).

· All-source and RPS solicitations need to employ the solicitation bidding guidelines outlined in Section VII.D (pg. 125).

· Following the "loading order" contained in the EAP is the first priority for IOU resource procurement, meaning that cost-effective EE and demand-side resources should be employed first. When these opportunities are captured, renewable generation is to be procured to the fullest extent possible - whenever an IOU issues an RFO for generation resources, it must justify its selection of fossil generation.

· 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 RPS targets in 2005 and beyond. If an IOU succeeds in procuring sufficient renewable resources to meet its 2005 RPS APT via an all-source RFO, it will not be required to undertake an RPS-specific solicitation next year.

· 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 quantitative108 attributes associated with each bid.

· GHG adders are to be used when evaluating fossil and renewable bids in all-source open RFOs.

· DE 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 COC proceedings but should instead use the methodology outlined in this decision.

· IOUs will not be allowed to recover initial capital costs in excess of their final bid price for utility-owned resources, but any cost savings will be shared 50/50 between ratepayers and shareholders.

· The IOUs will be required to use an IE in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders.

B. 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, Sempra 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. D.04-01-050 noted that ORA had 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 IEs. 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.109 Finally, we reaffirm our prior commitments to revisit our affiliate transactions rules in our open docket on that subject or a successor proceeding, to ensure that proper rules are in place based on the policy we adopt here.

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

The use of 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.110 In short, guidelines will allow FERC to more easily identify transactions that are consistent with the public interest, and, therefore, expedite their approval.111

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.112 Preferably, the independence criterion would be the same as that of an ISO or RTO.113 In this context, "independence" means that the third party's decision-making process is independent of the affiliate and all bidders.114 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." 115

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 Palomar116 was not given special treatment".117 Dr. Boothe's primary purpose was to ensure that "all competitors were treated fairly."118 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."119

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 PRGs provide sufficient independent review of IOU procurement decisions and that there is no reason to change the current structure".120

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." 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".121

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 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"122 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. 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."123

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 a 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 ED. Alternatively, ED 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 ED 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 IE process to provide firm assurances to the power market. We are open to comment from parties on specific conflict of interest standards.

D. Comparing PPAs to Utility Ownership

1. Parties' Positions

PG&E proposes to conduct two parallel solicitations, one to obtain long term 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 DE becomes irrelevant to the choice between 3rd party and IOU-owned generation, except as between competing PPAs.124

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.125

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. SDG&E opines that it is preferable to conduct this analysis on an RFP-specific basis to ensure that each project's unique circumstances and attributes are captured. SDG&E argues that 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, TURN contends that the Commission should not focus on comparing the value of PPAs to IOU-owned projects. Instead, TURN urges that the Commission to adopt the principle that the IOUs will acquire the resources that provide the lowest net cost to ratepayers, regardless of ownership form126.

ORA's concerns over head-to-head competition between PPAs and utility owned resources center around balancing Commission and legislative 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 3rd 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 3rd 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. 127

While the Commission has stated a preference for a hybrid wholesale electric market consisting of PPAs and IOU owned resources128, 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 quantitative 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 competitive129." Consequently, IOUs will not be allowed to recover initial capital costs in excess of its final bid price for utility-owned resources. See solicitation bidding guidelines outlined below.

All-Source and RPS Solicitation Bidding Guidelines

· 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).

o Negotiated bilaterals are discouraged - they will be evaluated on a case-by-case basis.130

· Bids should reflect total cost (generation and transmission) of delivery to load. 

· Bids from Utility-owned generation (IOU-build, turnkey, and buyouts) will be capped at initial capital costs.

o If actual costs come in under the capped bid, then there should be a 50/50 sharing of savings between ratepayers and utilities.

o Utility-owned resources that are selected in a solicitation will be eligible for Cost-of-Service ratemaking (future plant additions, annual O&M expenses etc.).

· Utility-built resources that are selected in a solicitation will file a CPCN with the Commission.

o Solicitation - CPCN process: CPCN process incorporates need determination, cost caps, and CEQA review. Having said that, bid cap would come from the RFO process, need determination would come from the approval of the Long-Term Procurement Plan. The only issue left to be addressed in the CPCN is the CEQA review.

· If an IOU considers the bids from a particular solicitation too high they have the right to terminate the solicitation. However, the IOU will need to reissue another solicitation if they want to file a CPCN with the Commission. They will not be allowed to file a CPCN for a project unless it was selected in a solicitation.

E. Debt Equivalence (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."131 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."132 PG&E proposes that the impact of DE on the utilities' financial condition should be addressed in the 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.133 All three 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 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 procurement 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.

We acknowledge that DE is a subjective factor based on the credit rating agencies' perceived risk associated with PPAs. The credit rating agencies' views on such risk are not static and can change with respect to a particular PPA during the term of the PPA. In addition, the imputed DE costs for existing PPAs will be reduced as the regulatory climate in California improves. However, as imprecise and subjective as it maybe, DE is a real cost that needs to be considered when evaluating bids from a PPA vs. a utility-owned resource. As SDG&E states, "[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."134 Consequently, the IOUs should take into account the impact of DE when evaluating individual bids in an all-source and RPS RFO, regardless of whether it is a fossil, renewable, or an existing QF resource.

Regarding DE imputation methodology, all three IOUs used the S&P methodology135 as the starting point for their proposed DE calculations because it is the most developed and transparent approach to calculating DE. We agree with the IOUs and adopt the same methodology for calculating DE, but with some modifications. Specifically, we believe that the 30% S&P risk factor is too high to be reasonable and fair to all PPAs. We find it logical 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.

Therefore, the IOUs will use a modified S&P methodology that employs a 20% risk factor for all PPAs, rather than S&P's 30% risk factor. While several parties endorse resource-specific DE risk factors (i.e., lower DE for renewables), we reject this approach because, as SCE and SDG&E have noted136, the rating agencies are indifferent to resource type when calculating the DE impact of a PPA.

While we are not saying that there are no other costs or risks that apply when evaluating a PPA vs. a utility-owned resource, this DE methodology should be used by the utilities and/or the IE when evaluating bids in an all-source and RPS RFO. The IOUs will also need to demonstrate, on a total portfolio basis, the DE impact of the PPAs in the Cost of Capital proceeding. As the rating agencies' views on DE change or as we gain more experience with DE evaluation in the COC proceedings, we may adjust the DE methodology used in future. Inasmuch as DE captures any increased financial risk to the IOUs, we may also-in future COC proceedings-want to consider factors that decrease their risks or are of benefit to the utilities when determining their rate of return.

F. Climate Change Issues in the Long-Term Procurement Plans

1. Background

At the time of the issuance of this decision it is still not known if climate change regulation in the form of GHG emissions limits will be instituted. However, it is likely that GHG emissions will be regulated within the timeframe addressed in the utilities' LTPPs and the lifetime of the utilities' long-term resource commitments. Therefore, it is appropriate for us to consider policies that would limit the exposure of IOU ratepayers to risks associated with this future regulation. California, and in particular this Commission, along with the CEC and CPA, has given clear signals of its intent 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 in addressing climate change 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." 137

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." 138

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 change:


"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 data139 - and proposes using $8/ton, consistent with the data in the now final E3 Report on Avoided Cost.140

NRDC proposes that the Commission direct the IOUs to financially impute a dollars-per-ton CO2 value into the analysis of all fossil bids and in their next LTPPs; require the IOUs to include in their next LTPPs the emissions profiles compiled by CA Climate Action Registry; and instruct the IOUs to "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 LTPP 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.

2. Party Comments on GHG Issues in the Proposed Decision

Climate change issues elicited a substantial amount of controversy in party comments to the proposed decision141. UCS, ORA, NRDC, and TURN all support the PD's approach, while PG&E, which is employing such an approach in its internal planning efforts, is silent in its comments. Other parties commenting on the issue were critical, typically arguing that the time is not right for action to address climate change, or that the Commission should collaborate with other regulatory and legislative bodies to enact GHG regulation at a higher level.

We find that taking action now is supported by our record, consistent with state policy and compatible with both existing law and ongoing Commission and state programs. The process of employing bid adders does not result in the Commission establishing wholesale rates for power, as SCE contends; bid prices for wholesale electricity do not change in any way. Winning bidders receive the price they offer in a competitive, all-source solicitation. Instead the adders, which are established with reference to a range of market signals and regulatory actions that reveal the future financial risks associated with greenhouse gas emissions, will aid in the selection of those energy resources that are clearly preferred by the state of California. This Commission is acting in the best interest of California ratepayers in taking this action now, and we look forward to collaborating closely with all stakeholders in the further development of our climate change mitigation strategies. We also intend to work with other policymakers and stakeholders in the future to ensure that we can implement on a competitively-neutral basis going forward.

Moreover, the adoption of a GHG adder policy now does not preclude, and in fact is fully compatible with, the adoption of other climate change mitigation policies in the future - including a possible GHG content requirement, or "cap", and the possibility of a GHG trading system. Adoption of an adder policy now is likely to support - not limit - the development of such policies in the future, should our evaluation of the SkyTrust proposal and similar options (discussed below) indicate that such policies are desirable.

3. Range of values for the GHG Adder

IOUs are directed to employ a GHG adder when evaluating fossil and renewable bids received via an all-source RFO. Utilizing data from the record in this proceeding, following is a range of values for this adder:

Consistent with established Commission policy and the positions of several parties, including PG&E, we adopt a range of values to explicitly account for the financial risk associated with GHG emissions of $ 8 to $25 per ton of CO2, to be used in the evaluation of fossil generation bids. This range is taken from information in the present record, and is consistent with actions undertaken by other electric utilities across the country. Each IOU will select a value within the adopted range and respond to party comment on the value, before employing the adder in analyzing RFO responses.

The GHG value will be added to the prices bid in future RFOs, and will be used to develop a more accurate price comparison between and among fossil, renewable and demand-side bids. Regardless of which bid is ultimately selected, the adder will not be paid to that generator or charged to ratepayers; it is an analytic tool only. Winning bidders are to be paid the prices that they bid. Thus, the effect of the adder is to potentially change which bids and resources are selected - not to change the price of selected bids. Bidders must provide the electricity products sought in the all-source solicitations before the IOU will be required to employ the GHG adder.

In addition to the GHG adder, the IOUs are directed to employ, when finalized and approved by the Commission, the additional environmental avoided cost 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. All procurement commenced 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. Additionally, the IOUs will use the values adopted in R.04-04-025 in their next LTPPs when modeling alternative resource portfolios and selecting a preferred portfolio.

In a separate phase of this proceeding, we will be evaluating a procurement framework modeled after the cap-and-trade principles of the Sky Trust.143 Under that proposed framework, the Commission would establish annual limits on carbon-based energy procurement as a means to meet the Commission's EAP goals and minimize utility contribution to climate change. We will address the effectiveness of this proposal, as well as other approaches to "carbon caps" on utility procurement, to minimize utility contribution to climate change, in subsequent decisions in this rulemaking docket or other appropriate proceedings. For this purpose, the Assigned ALJ and/or Assigned Commissioner may direct Commission staff to perform additional analysis or studies, as needed. We intend to put in place a procurement incentive framework after considering the cap-and-trade Sky Trust proposal as well as other approaches (e.g., specific carbon emission limits) by the end of 2006, or as soon as practicable.

Application of the GHG adder is not required for contracts less than five years in duration, which is the standard adopted in this decision regarding requirements for Commission pre-approval. For contracts longer than five years, the adders should be employed in evaluating the cost of power procured in 2007 and beyond (i.e. power delivered in 2005 and 2006 should in no instances have the adders applied when costs are evaluated by the IOU).

G. Repowering

West Cost Power refers collectively to the limited liability companies that own and operate approximately 2,300 MW in Southern California. The power plants producing those MWs are Encina, El Segundo and Long beach. These are extant power plants that are often referred to as "aging" power plants, and/or facilities on "brownfields.".144 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 recommends that the Commission make a finding that redevelopment of conventional resources in load pockets is a valuable resource and that the IOUs should be directed to give high priority to such brownfield resources before they consider the use of conventional resources at greenfield sites. WPC believes that redevelopment of an existing site is good public policy that benefits California. In WPC's opinion, repowering at existing sites, that are already interconnected to gas transportation system, possess rights to water needs, have acquired environmental permits, and have in-place measures to mitigate environmental impacts, would allow redeveloped plans to come on-line faster than comparable greenfield plants.

WCP argues that the EAP and the Commission have recognized the importance of repowering older, less efficient plants and believes the IOUs should be directed to respond to those policies by giving priority to repowering and redeveloping existing power plants. 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.

SCE disagrees with WCP's position that brownfield sites should receive priority over other options. SCE points out that WCP's position is self-serving and that the majority of parties, including ORA, agree with SCE. SCE argues that WCP's position is that all repowered sites receive preference over new generation, not just the ones that are located in load pockets. SCE argues that these plants already possess significant location market power, which the Commission will further exacerbate by giving them priority in RFPs. SCE states that the Commission should not favor these plants if they cannot win an RFP when compared to new generation. SCE suggests RMR contracts for these plants to limit their market power. SCE argues that the benefits of brownfield sites such as the 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 LCBF 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 LCBF should be the overarching principle of procurement for providing the best value to its customers.

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

SDG&E believes that it should not be directed to sign multi-year contracts with aging power plants in its service territory as a strategy for preserving these plants regardless of whether or not SDG&E has a need for such resources. SDG&E notes that it should not provide a preference for brownfield sites in its resource plan. SDG&E believes that there is no need for a preference in a competitive solicitation.

1. Discussion

Parties have presented two issues: (1) Whether the IOUs should be directed to sign multi-year contracts with aging power plants, and (2) Whether IOUs should give priority to brownfield sites over greenfield sites.

Several parties recommend that the Commission direct the IOUs to sign multi-year RMR contracts with local aging power plants. PG&E seems to agree with this recommendation, while SCE and SDG&E oppose it. PG&E asks the Commission for authority to enter into multi-year contracts in 2005 and states that these types of contracts could help keep facilities, including the aging power plants, on line.

Although the Commission has adopted the policy to minimize reliance on RMR contracts, it has recognized that RMR contracts will remain in the future to address market power. Furthermore, local reliability, and deliverability govern the need for RMR contracts. While we recognize the advantages of IOU contracting with some power plants in minimizing the need for RMR contracts, we do not direct the IOUs to engage in a particular contract, if that contract is not in the best interest of the ratepayers. The Commission has adopted the policy of LCBF which dictates that the IOUs obtain the best and most cost effective product for their customers.

As WPC states, developing brownfield sites is consistent with the Commission and the EAP's stated policies. In recognizing the importance of repowering, in D.04-01-050, the Commission stated that:


"To the extent that new generation resources are required, the utilities should first consider the overall advantages of repowering at existing plants or of development of brown field sites located close to load rather than development of new green field sites remote from load and requiring substantial transmission and other upgrades to the system. We prefer that generation assets be sited in California and that they minimize the overall economic and environmental impact, including the costs of transmission and power losses."

Also, the EAP has a stated action to: "Add new generation resources to meet anticipated demand growth, modernize old, inefficient and dirty plants....."145

To this end, we agree that modernization of old, inefficient, and dirty plants should be among IOUs' first choices of resources. However, we are concerned that the LCBF process would not allow positive attributes of a brownfield site to be fully considered or fairly assessed (for example, the risk of delay in construction of a new site). We disagree with SDG&E's position that the RFP Process should automatically incorporate the positive attributes of the brownfield sites. It is generally good policy to consider brownfield sites before developing greenfield sites, because of existing infrastructure, being close to load centers, and many other benefits. Therefore, we direct the IOUs to consider the use of brownfield sites first and take full advantage of their location before they consider building new generation on greenfield sites. If IOUs decide not to use brownfield, they must make a showing that justifies their decision.

98 D.04-01-050, mimeo., at 61

99 Calpine opening brief, p. 12.

100 Id., pp. 11, 12.

101 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).

102 SCE opening brief, pp. 88, 90.

103 SDG&E opening brief, pp. 96-97.

104 Sempra opening brief, pp. 3-4.

105 WPTF opening brief, pp. 11-13.

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

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

108 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.

109 D.04-01-050, pp. 72-74.

110 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.

111 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.

112 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.

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

114 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).

115 108 FERC 61,081, p.27-29.

116 "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.)

117 D.04-06-011, p.48.

118 Id., p.52.

119 Calpine Reply Brief, p.18.

120 Calpine Reply Brief, p.18.

121 Opening Brief, p.17-18.

122 SDG&E opening brief, pp. 102.to104.

123 SCE opening brief, p. 64.

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

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

126 TURN opening brief, pp. 12

127 Calpine opening brief, pp. 10-12.

128 See Hybrid Market section in this decision.

129 Calpine opening brief, pp. 12

130 The procurement mechanism (solicitation, bilateral etc.) for repowered renewables will be determined in R.04-04-026.

131 SCE/Simpson Ex. 73, 21:2-5.

132 SDG&E opening brief, p. 89.

133 PG&E opening brief, p. 51.

134 SDG&E opening brief, p. 89.

135 PG&E Opening Brief pg. 51, SCE Opening Brief pg. 86-88, and SDG&E Opening Brief, pg. 93-96

136 SCE Opening Brief p. 88, , and SDG&E Opening Brief, pp. 95-96

137 D.04-01-059, p. 108.

138 R.04-04-003, Appendix B, p. 5.

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

140 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.

141 Parties commenting on climate issues in the Proposed Decision include CAC/EPUC, CLECA/CMTA, IEP, NRDC, ORA, SCE, SDG&E, SEMPRA, SVMG, TURN, UCS and WPTF.

142 PacifiCorp, IPC and EIA estimates sited in NRDC opening brief, 10/18/04, p.16-17

143 R. 04-04-003, Appendix B.

144 Brownfield sites generally refer to locations where there are existing power plant and/or other heavy industrial facilities. Greenfield sites, on the other hand, generally refer to locations that currently do not have power generation facilities and/or other heavy industrial facilities already on site.

145 EAP, p. 6

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