IV. Discussion

Two weeks' worth of evidentiary hearings, over 100 exhibits, and multiple feet of testimony and briefs leave the Commission with a conundrum for SDG&E, its electricity users, and its ratepayers: what steps should the Commission take now to ensure that the exigent circumstances that led to the energy crisis -- both in loss of reliability and skyrocketing costs -- do not occur again?

One way to achieve this goal is for the utility to have a balanced portfolio from all qualified resources with a mix of different ownership types, from PPA to IOU ownership, along with diversity in fuel source, pricing terms, and contract lengths. The resource mix also should include sources such as demand reduction products and renewable resources to help the state in meeting its articulated goals of promoting alternative energy resources. The Commission also wants to: (1) promote the goals of the Energy Action Plan (EAP) for California, which calls for more in-state, state-of-the-art generation;²¹ (2) follow the legislative mandate of AB 57 that requires electric corporations to have a diversified procurement portfolio; and (3) be consistent with the decisions we have issued in this OIR, including D.02-12-074, which adopted the utilities' 2003 short-term procurement plans, D.03-12-062, adopting a 2004 short-term procurement plan, and D.04-01-050, establishing a long-term regulatory framework for power procurement by the utilities.

To this end, the Commission must balance the need of SDG&E to add new generation resources to meet anticipated demand growth, replace many of its older, aging, less efficient energy sources with more efficient, lower emission, environmentally cleaner plants, reduce the increasing RMR costs that result from using the older facilities to serve the RMR contracts, and maintain adequate reserves. All of the studies performed by SDG&E indicate that the utility needs new generation to meet both its short-term and long-term local reliability grid needs. In addition, SDG&E's existing transmission system is not adequate to serve the immediate needs of its customers, and does not provide any avenues for the utility to transmit power from outside of its service territory or to increase the movement of power within its territory.

The question then becomes, how much new generation is needed when and where in SDG&E's service territory, and how much reserve is prudent as an insurance policy against exigent energy circumstances. Insurance, in the form of extra generating capacity, brings with it a ratepayer cost. This cost could escalate if anticipated load growth does not occur, or if the Legislature, or this Commission, makes policy changes in the areas of direct access, core/non-core, community aggregation, that affect the dynamics of SDG&E's customer base. Technology is also always improving, and what is state-of-the art today -- in terms of qualities such as heat rate, efficiency and environmentally friendly power -- might not be viewed as efficient or cost-effective as time passes.

This Commission is also painfully aware of the lessons learned from the 2001 energy crisis and the emergency steps that were taken to bring California and its ratepayers out of the crisis. Certainly the hardest lessons were learned from some power contracts that DWR negotiated to allow California to keep its lights on. While the contracts restored reliability, many of them were at above-market prices, and ratepayers are now saddled paying these high rates for years to come.

We must evaluate the five proposals submitted by SDG&E, and their attendant ratemaking mechanisms, in light of these competing and complex factors. SDG&E presents the Commission with five proposals to meet its grid reliability needs: Comverge, Envirepel, Ramco, Palomar, and Otay Mesa. In addition to meeting grid reliability, Comverge fills a demand reduction need, Envirepel fills a renewable resource need, Ramco and Palomar give SDG&E turnkey utility owned projects, and Otay Mesa presents an additional resource to the utility to offer benefits to ratepayers for increased reserve margins and efficient, economical and environmentally superior power.

Taken together, SDG&E argues that these five resources allow it to have a balanced portfolio of resources that will not only meet its growing needs but will also support the retirement of older, more costly, less efficient, power sources. We agree that SDG&E's five proposals, taken together, do achieve a reasonable balance among the complex and competing policy goals that this Commission must attempt to satisfy, and, for the reasons that are discussed in more detail below, we will approve the five proposals that SDG&E has submitted to us.

Our approval of the five proposals that SDG&E has submitted does not mean that there are not other proposals that might, under the right circumstances or at other times, be able to meet SDG&E's grid reliability needs. However, there is nothing in the evidence presented in this proceeding that leads us to conclude that SDG&E picked the wrong projects or should have picked other projects that were submitted in response to its RFP in lieu of the proposals it presented for our approval. The evidence presented in the hearings on this matter shows that SDG&E's selection of the five projects that it has proposed was reasonable and in the long-term interest of SDG&E's ratepayers.

We are aware that some of the unsuccessful participants in the RFP process have questioned the reasonableness of SDG&E's selection of one or more of the successful proposals, as well as the fairness of the RFP process itself. However, the evidence presented in the hearings on this matter shows that SDG&E's decision to disqualify, or not to select, the unsuccessful proposals was reasonable. None of these unsuccessful proposals was better than any of the successful proposals, and all of the unsuccessful projects posed problems or involved uncertainties that were not triggered by the proposals that SDG&E did select. Moreover, the evidence shows that the RFP process was fair to all of the bidders. SDG&E went so far as to hire an independent observer to document that in the negotiating process leading up to the submittal of the successful proposals, SDG&E dealt with all bidders in an arm's length and even-handed manner.

What follows is a discussion of the reasons supporting our approval of the proposals that SDG&E did select. To the extent that certain parties have objected to these proposals, those objections are addressed. However, we do not consider ourselves obligated to provide a comparable analysis of SDG&E's rejection of the unsuccessful participants in the RFP process. The evidence presented by SDG&E provided an ample explanation of the reasons for rejecting the proposals that it rejected. For example, Duke South Bay 4 would not have provided any cost benefits to SDG&E's ratepayers.²² The Nevada Hydro proposal was highly speculative, and was predicated on the passage of federal legislation allowing a transmission corridor through a National Forest that has yet to be realized.²³ The Celerity demand response proposal was not, in fact, a true demand response project, and was shown to be uneconomic when compared to other supply-side proposals SDG&E was considering.²⁴

Although we shall not consider further the complaints of the unsuccessful bidders with regard to why their projects should have been selected in preference to those projects that were submitted for our approval, there are several more generic procedural issues raised by the unsuccessful participants that we shall address at the conclusion of this discussion.

A. Demand Response: Comverge

The Comverge proposal planned to utilize Direct Load Control (DLC) during the summer months to manage customer end-use equipment, specifically central air conditioning units, electric water heaters, and pump motors. The initial proposal submitted in the RFP targeted residential, small commercial, and irrigation customers for the installation of DLCs. The proposal was then modified to only target commercial customers with maximum demands no greater than 100 kW and irrigation customers with demands less than 200 kW, and to exclude residential customers. SDG&E's witness stated that Comverge was asked to modify its proposal regarding the residential customers to avoid conflict, duplication, or overlap with other concurrent residential demand reduction programs. Comverge agreed to modify its proposal and submitted its revision that estimated achieving between 25-30 MW in load reduction within three years. Pricing was adjusted slightly upward to account for the anticipated higher incentives required for small business customers to participate in the program.

SDG&E recommends that the Commission approve the Comverge contract because the utility believes it would contribute to the MW targets listed in SDG&E's LTRP and will support the annual demand response targets as set forth in R.02-06-001. Because the Comverge proposal was modified to only target the commercial and irrigation customers, and not residential, the costs of implementing the program over the 10-year period of the contract are uncertain. Comverge was unwilling to assume the entire risk of this program, so SDG&E agreed to a 75/25 SDG&E/Comverge cost sharing with a payment cap. Comverge will receive 75% of its costs during the first three years amortized over the remaining years of the contract term if it achieves less than 90% of the demand response target of 30.2 MWs. As agreed upon, the expected demand reduction level in 2005 is 8.7 MWs, in 2006 is 19.5 MWs, and in 2007 is 30.2 MWs.

ORA agrees that this cost sharing and payment cap is reasonable and recommends Commission approval. PG&E, Coral Power, Intergen, InterGen, and Sempra take no position regarding Comverge. Nevada Hydro does not specifically oppose the Comverge proposal, but finds all of SDG&E's recommended proposals not reasonable because of the flawed RFP process. Celerity does not specifically address the Comverge demand response proposal, but champions that its own demand response proposal should also go forward.

The only party raising questions to the Comverge proposal is TURN/UCAN. Succinctly put, the consumer groups are skeptical of the revisions to the Comverge proposal that eliminated the residential customer sector from the program. From TURN/UCAN's perspective, residential air conditioner (AC) customers, in fact the consumer group that was initially targeted in Comverge's proposal, have a high rate of success in subscribing to and in responding to reduced load incentives. This fact is bolstered by the fact that when only residential AC customers were the target, Comverge bore the risk of any underperformance due to inadequate subscription. TURN/UCAN find SDG&E's explanation that they refocused the program to avoid overlap with other ongoing demand response programs utilizing residential customers statistically faulty.

TURN/UCAN advocate directing SDG&E to revisit the Comverge contract and either return to the original residential AC customer target, or add some residential AC customers into the mix of commercial and irrigation customers. In all instances, however, TURN/UCAN wants the SDG&E shareholders to assume the risk of underperformance in the commercial sector.

1. Cost Recovery and Ratemaking Mechanism

SDG&E requests that the Commission follow the precedent established in D.03-03-036 for current demand response programs, with the exception that one-time set-up, capital and on-going costs associated with Operating & Maintenance (O&M) and Administrative and General (A&G) expenses associated with the Comverge contract should be recorded in an Advanced Metering and Demand Response Account (AMDRA). SDG&E proposes that the year-end balance in the AMDRA be recovered from all customers through distribution rate changes effective January 1 of the following year. Any incentive payments paid to participants in the Comverge program should be recorded in the AMDRA, instead of through commodity rates as established in D.03-03-036. SDG&E justifies this mechanism since the Comverge program will be offered to both bundled and direct access customers, so incentive costs should be recovered from all customers through distribution rates. Any revenue shortfalls can be recovered either through balancing account treatment or through the AMDRA.

2. Conclusion

We find that the record supports SDG&E's proposal to enter into a contract with Comverge, with a cost sharing of 75/25 SDG&E/Comverge with the payment cap as proposed.

We also adopt the mechanism SDG&E proposed for the recovery of the costs associated with the Comverge contract which is to follow the precedent established for demand reduction programs in D.03-03-036, with the exception that O&M and A&G expenses incurred in the implementation of the contract will be recorded in the AMDRA and will be recovered from all customers through distribution rate changes effective on January 1 of the following year. Also, any incentive payments should be recorded in the AMDRA and recovered through distribution rates, instead of from commodity rates as established in D.03-03-036.

B. Renewable: Envirepel

The Envirepel renewable project, is a biomass project,²⁵ will be located in Fallbrook, within SDG&E's service territory, and will be capable of delivering 40 MW net of firm capacity and energy for a term of 15 years. In addition, Envirepel will make available to the utility an additional 5 MW of non-firm energy at the lesser of contract or market, upon request by SDG&E.

The logistics of the Envirepel contract for renewables is that Envirepel proposes to contract with outside companies for delivery of green waste to be trucked to the facility site as fuel to be consumed by the project. Evirepel agrees that they will install the appropriate technology to allow for the clean burning of such green waste.

SDG&E, through its witness Bartolomucci, urges the Commission to approve the contract with Envirepel for renewable because of the following attributes: (1) the project is required to achieve full commercial operation no later than June 1, 2006; (2) there is an all-in total price of $50.00/MWh over the 15-year term of the contract; (3) SDG&E has an option to purchase an additional 5 MW of energy, when such energy is available from the plant, at a $25/MWh price; and (4) the plant may be physically curtailed by the utility for up to 200 hours annually and economically curtailed for up to 800 hours annually.

SDG&E believes the Envirepel PPA is a well-suited renewable project to meet its grid requirements in the 2005-2007 timeframe. This project also presents a technology that has not previously been included in the utility's resource mix and may be able to provide additional reliable renewable energy capacity in the future, at comparable costs to other renewable projects. SDG&E requests that the Commission approve the Envirepel contract as reasonable.

No party opposed this proposal.

1. Cost Recovery and Ratemaking Mechanisms

SDG&E proposes that the costs related to the Envirepel contract should be recorded in the Electric Resource Recovery Account (ERRA) for the purpose of recovering them through commodity rates.

2. Conclusion

We find the Envirepel PPA proposal is supported by the record as a well-suited renewable project and we approve the SDG&E/Envirepel contract as presented. We also adopt the cost recovery mechanism proposed by SDG&E for the Envirepel PPA: costs for this contract should be recorded in the ERRA for the purpose of recovering them through commodity rates.

C. Ramco

Ramco offered a turn-key deal, a three-year PPA with the obligation to sell at the end of the term, and a 10-year PPA with an option to purchase. SDG&E's witness Schneider testified that the turn-key proposal was the least cost of the three proposals. SDG&E is therefore recommending that the Commission approve Ramco's 45 MW LM 6,000 combustion turbine project which Ramco proposes to sell to SDG&E on a turn-key basis. Ramco will design, permit, and construct the turbine in Chula Vista, and will transfer title to SDG&E when it is fully constructed and in operating condition. The utility will use this facility for intermediate load requirements beginning in June 2005.

Even though this is a turn-key project, SDG&E will have some involvement in the oversight of the project during construction, including the specifications of the turbine package, so the utility can be satisfied that the project meets with its satisfaction. Additionally, the proposal provides the benefit of utility ownership of generation. SDG&E requests that the Commission approve the Ramco proposal and its attendant cost recovery, ratemaking, and revenue requirement.

No party opposes the acquisition of the Ramco turn-key proposal, but TURN/UCAN, ORA, and others do not endorse the associated ratemaking treatment. In particular, TURN/UCAN object to SDG&E's requested premium adder to its approved return on common equity (ROE) associated with new investments in utility-owned generation. In summary, TURN/UCAN strongly disagree with the arguments posited by the utility in support of this ROE premium, and at a minimum argue that the issue should be deferred to the next round of capital proceedings.

1. Cost Recovery and Ratemaking Mechanisms

SDG&E proposes that it be compensated for the general risks inherent in the ownership and operation of major generation facilities through a return on the generation investment that is set at a basis point premium over SDG&E's adopted return on equity for distribution rate base. SDG&E justifies this request for an additur on the basis that there is uncertainty surrounding state and federal energy policy, a lack of legislative direction on recovery of investment in generation assets, and uncertainty of the stability of the future retail customer base. Specifically, SDG&E argues that the future of its customer base will be affected by movements in the areas of direct access, community aggregators, municipalization, and core and non-core. The uncertainty surrounding the ever-changing energy environment makes investment in generation risky -- and SDG&E suggest that a basis point premium mitigates that risk.

SDG&E further requests that the Commission adopt a generation ratemaking plan for SDG&E's investment in the Ramco and Palomar facilities that is separate from distribution ratemaking. SDG&E identifies the proposed generation revenue requirements for both Ramco and Palomar as set forth in their respective term sheets, subject to adjustments for escalation factors and possible changes to inputs. In addition, the revenue requirements will include expected values for the O&M costs. SDG&E asks the Commission to adopt the initial revenue requirements for these facilities simultaneously with approval of the new investments, so the utility is ensured of recovering all reasonable costs without hindsight review.

The revenue requirements for Ramco and Palomar will include a rate of return (ROR), that is based on SDG&E's authorized capital structure, its embedded costs of debt and preferred stock, and ROE. A key component of SDG&E's ratemaking proposal for Ramco and Palomar is a 75 basis point premium over its authorized distribution ROE for its ROE on generation investments. The current ROE for distribution is 10.90%, and with the added basis points, SDG&E is requesting a ROE for generation of 11.65%. SDG&E argues that it should not have to wait till the next cost of capital proceeding to address the appropriate ROE for its proposed generation investments because: the utility is entitled to a fair return; generation is riskier than distribution; Ramco and Palomar are large investments for SDG&E (approximately 25% of the utility's existing rate base); and it is important for the financial community to know that the Commission appreciates the risks associated with generation investments.

2. Conclusion

We find that the Ramco combustion turbine acquisition is supported by the record and approve this turn-key approach. We will approve the contract when it is submitted to the Commission.

We also approve the cost recovery, ratemaking and revenue require proposals that were requested by SDG&E. Specifically, we approve a higher rate of return on the Ramco and Palomar facilities that SDG&E will be purchasing and operating as utility-owned generation assets, and we also approve the initial revenue requirements and the ratemaking process for these facilities that SDG&E has proposed.

We approve SDG&E's proposed cost recovery and ratemaking proposals in light of a number of compelling policy considerations. One, SDG&E's acquisition of the Ramco and Palomar facilities will constitute SDG&E's first investments in new generation facilities for many years -- since well before electric restructuring began and AB 1890 was conceived. In fact, these investments will be the first investor-owned utility investments in generating facilities in California, completely under California regulation, in well over a decade. Two, the chaotic and ever-changing energy environment since the adoption of AB 1890, including the energy crisis of 2001, has caused, and is causing, constant recalibration of state and Commission policies toward the present and future rights and obligations of investor-owned utilities, providers of DA, community aggregators, local jurisdictions proposing municipalization, and other stakeholders in the energy service industry. And three, SDG&E's decision to invest in significant new generation assets is not without substantial risk. The potential for stranded generation investment is as great as it has ever been, and policies relative to a public utility's obligation as the electric provider of last resort continue to be in flux. Given the continuing uncertainty surrounding state and federal energy policy, the lack of clear legislative direction on recovery of investment in generation assets as compared to purchase power contracts, the uncertainty pertaining to the stability of SDG&E's future retail customer base, we recognize that there are now greater risks for a public utility that invests in major new generation facilities that those associated with the ownership and operation of electric distribution facilities.

a) Return on Equity

The 11.65% ROE that SDG&E has requested for the generation assets it proposes to acquire amounts to a 75 basis point premium over SDG&E's authorized distribution ROE of 10.90%. SDG&E provided ample explanation why a unique ROE should be used for SDG&E's investment in new generation facilities. SDG&E's witnesses McMonagle and Morin conclude that the appropriate generation premium over distribution is in the range between 75 and 100 basis points.²⁶ In addition, SDG&E points to Public Utilities Code §454.3 as demonstrating a legislative intent to provide an incentive rate of return to utilities that develop and operate generating facilities which meet or exceed applicable environmental pollution standards and whose costs are less than existing generation facilities.

TURN/UCAN has argued that SDG&E's position on risk relative to generation assets is "undermined" by SDG&E's proposed cost recovery and rate mechanisms, we also understand SDG&E's concern that our approval of those mechanisms does not eliminate all the various risks surrounding SDG&E's generation investment.²⁷ Even if the uncertainties regarding the stability of SDG&E's customer base are resolved, generation assets will continue, as they have in the past, to be more "risky" investments for utilities than investments in distribution assets. Transmission and distribution are less risky, because these services are in the nature of a natural monopoly. By contrast, now, in light of the restructuring of electricity markets that has encouraged an open market in generation, it is particularly challenging for a regulated utility to align its generation costs with the price for power, especially when that price is very volatile. Moreover, investments in generation assets tend to be "large and lumpy."²⁸ If something goes wrong with a generation asset, the chances of it being substantially more costly to repair than a defect in a distribution asset is high. Further, regulatory and legislative policy change tends to affect utility investments in generation assets more than distribution assets.

We accordingly accept SDG&E's argument that there is a comparatively greater intrinsic risk of utility investment in generation assets than those in distribution assets, and we do not agree with TURN/UCAN that SDG&E's position on this point (as reflected in the testimony of SDG&E witness Morin) is somehow "undermined" in any way by SDG&E's ratemaking and cost recovery proposals. TURN/UCAN even had to agree that generation assets are more risky than distribution assets.²⁹

Moreover, we are satisfied that we should not defer answering this question of the appropriate ROE for SDG&E's proposed generation investments until SDG&E's next cost of capital proceeding. Those reasons include the following. One, there is a well-established legal principle to the effect that a utility is entitled to a fair return generally equivalent to that achieved by investors in other firms that face similar risks. See, Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944); Bluefield Water Works and Improvement Co. v. West Virginia Public Service Commission, 262 U.S. 679 (1923). Two, SDG&E's current distribution ROE has no relationship to the risks of generation. In the last cost of capital proceeding, the assigned ALJ required that only testimony related to the risks of distribution could be addressed. Three, the proposed investments in the Palomar and Ramco projects are extraordinarily large investments for SDG&E. In round numbers, those investments approximate $500 million, which is approximately 25% of SDG&E's existing rate base of a little over $2 billion. And four, it is important for the financial community to know that the Commission is going to acknowledge the significant risks related to utility investment in generation assets. The investment community, particularly from a rating agency perspective, will be watching to see if the Commission acknowledges the additional risk related to generation assets.

This all being said, we are not, however, prepared to grant the full 75 basis point premium that SDG&E has requested. Although we believe that SDG&E's proposed investment in large new generation projects is somewhat riskier that its on-going investments in its distribution, we also believe that the fact that SDG&E is a regulated utility, the financial health of which is overseen by this Commission, somewhat mitigates that risk. We also believe that the cost recovery mechanism that SDG&E has requested, and which we shall approve, as is explained just below, somewhat mitigates that risk. We shall accordingly approve a 50 basis point premium over SDG&E's authorized distribution ROE of 10.90% for the generation assets that SDG&E proposes to acquire. This will result in an 11.4% ROE for SDG&E's new generation assets once SDG&E acquires those assets.

b) SDG&E's Financing Plan

SDG&E has indicated that it will finance the purchase of the Ramco and Palomar generation assets using debt, equity and preferred stock in proportions matching its CPUC-authorized capital structure. However, SDG&E has also indicated that its financing plan requires relatively more equity prior to purchase. SDG&E's specific plans are to: 1) maintain its current bank credit facility to assure liquidity for payment obligations; 2) retain earnings during construction so that SDG&E will have sufficient cash and equity both to pay for the plants and to maintain SDG&E's capital structure at the authorized level when the plants are purchased; and 3) add long-term debt and preferred stock near to the date when the plants are acquired to help pay the purchase price and/or refinance any borrowings under the credit facility that were needed to pay for the power plants.³⁰

SDG&E has indicated that its financing strategy for these turnkey projects is very similar to the strategy it would follow if SDG&E were to build the plants itself. The primary financial and credit characteristics of a major capital project are nearly identical, although the payment for a turnkey project is due in a lump sum at completion rather than during the course of construction. In either case, the financing must completed in advance of any payment date, and increasing amounts of equity should be available as construction proceeds to maintain credit fundamentals.³¹

If SDG&E were building the projects, project costs would be held in Construction Work in Progress (CWIP) and financing costs would be offset through AFUDC earnings. However, under the two turnkey proposals, equity will be retained and dedicated to the projects, but there will be no AFUDC earnings to offset the financing costs. SDG&E has accordingly requested reimbursement for its financing costs while the facilities are under construction, because it is prudent to accumulate equity (and debt) in advance of the payment dates to maintain credit standards and to assure that payments can be made when due.³² We agree with SDG&E that a regulatory asset should be established for this purpose in the same way that AFUDC covers financing costs for CWIP investments. This regulatory asset will accumulate the cost of equity that is held to pay project costs under the turnkey contracts, and it will become part of the cost of the generation facilities when the power plants are purchased. These amounts will be recovered through depreciation over the plant's lifetime like other project costs. However, the value in this account should be limited such that total capitalized financing costs (both at SDG&E and at the project) will not exceed the amount of AFUDC that would have applied had SDG&E built the facility.

We disagree with TURN/UCAN's position that the Commission should not consider issues related to recovery of the acquisition financing costs until after SDG&E purchases the assets in question. TURN/UCAN does not contest the premise that SDG&E needs to have funds available to purchase the Palomar and Ramco facilities, or that the costs associated with those funds should be reimbursed.³³ However, the delay in decision making that TURN/UCAN recommends could prevent SDG&E from executing either of the turnkey proposals based upon the uncertainty as to whether the Commission would approve the regulatory asset.

We agree that SDG&E needs the requisite assurance -- at the time we issue this decision approving SDG&E's grid reliability proposals -- that all reasonable costs associated with accumulating the equity necessary to purchase the generation facilities will be timely recovered. We shall therefore approve SDG&E's request that the costs associated with accumulating the necessary equity to purchase the new Ramco and Palomar generation facilities should be allowed.

D. Palomar

SDG&E is proposing to purchase from SER a 500 MW (base load)/ 555 MW (peaking load) combined cycle natural gas-fired generation plant to by 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.

When SDG&E realized that Palomar was an entry in the RFP, SDG&E knew its evaluation of the project would be subject to heightened scrutiny since the owner of Palomar, SER, is an affiliate of the utility. Therefore, early on in the process SDG&E retained an independent third party, Dr. Boothe, to observe the bid evaluation and selection process to ensure that Palomar was not given special treatment.

SDG&E alleges that Palomar emerged from the bid evaluation process as the "conforming bid winner" since it was the LCBF proposal from the RFP-even over Otay Mesa. The utility based this conclusion on a number of factors, including the cost of the Transmission System Enhancements SDG&E plans to do if the Otay Mesa project is ratified, the cost differential between a turn-key 30-year project and a 10-year PPA, and the benefits of utility ownership of the facility.

Once Palomar was chosen as the LCBF proposal, SDG&E testified that it focused on negotiating a fair price, and ensuring that the contract would meet the "no regrets" standard set forth in D.04-01-050. To apply this test, the Commission reviews not only the cost of the facility, but any savings, such as RMR cost reductions, that associated with the project.

SDG&E asks the Commission to find that the Palomar project is consistent with the utility's long-term resource plan, was the result of a competitive procurement process, and that the proposal and the cost recovery mechanisms requested by SDG&E allow the utility to fulfill its obligations to serve its customers at just and reasonable rates, benefit consumers, and are in the public interest.

SER agrees. SER urges the Commission to approve Palomar as the best option for meeting the grid reliability needs described in the RFP and emerged as the "best fit, least cost" project from the RFP. SER claims that the environmentally friendly, technologically advanced Palomar is located in an urbanized customer load center that presents no local or community environmental or siting concerns, requires a minimum of transmission upgrades, and has a superior heat rate that is obtained through the use of reclaimed water cooling. In fact, as SER asserts, only TURN/UCAN raised any criticism to the project.

The briefs matched SER's claims. Except for TURN/UCAN and Nevada Hydro, who opposes all of the proposals on the basis that the RFP was unfair, the parties either are silent on Palomar, or support it. Even Calpine, who has a competing large generation project, Otay Mesa , supports having SDG&E sign contracts with both Palomar and Otay Mesa. Calpine appears to take it as a given that Palomar will be acceptable to the Commission and strongly argues that Palomar should not foreclose the need for Otay Mesa as well in the utility's portfolio.

TURN/UCAN's brief articulated numerous concerns they had with the Palomar proposal. In summary, the consumer groups believe the plant is overpriced relative to the market and should reflect a price consistent with the fact that it is a distressed asset; it does not meet the "no regrets" test; other Palomar options that might have superior cost-effectiveness for SDG&E ratepayers were ignored; the cost-effectiveness evaluation of Palomar to Otay Mesa that shows Palomar wins hands down as a utility owned asset vs. a PPA is based on faulty assumptions and is fatally flawed; and Palomar has already obligated itself to serve DWR under SER's long-term contract.

From TURN/UCAN's perspective, SDG&E has not demonstrated sufficiently that it needs either one of the over 500 MW generation facilities for either its near-term LRA needs, or even its long-term needs. While TURN/UCAN appear to have fewer concerns about Palomar, as compared with Otay Mesa, they still urge the Commission to reject both proposals. The consumer groups are not convinced that the ratepayers need to saddle themselves with 10-year PPA and 30-year turn-key obligations when SDG&E has not established the need, and the costs do not seem to have been negotiated as low as they could go.

1. Cost Recovery and Ratemaking Mechanisms

The discussion of the cost recovery and ratemaking mechanisms set forth above under the Ramco proposal is equally applicable to the Palomar proposal and will not be repeated.

However, SDG&E also proposes a heat rate incentive for Palomar that has any accrued incentive rewards or penalties for the operation of Palomar recorded in SDG&E's ERRA and recovered in commodity rates. SDG&E also asks that its proposed heat rate incentive for Palomar be approved as part of the ratemaking mechanism for Palomar.

2. Affiliate Transaction Issues

As numerous SDG&E witnesses testified, and as discussed earlier, SDG&E took extraordinary precautions to ensure that all ATRs were followed and that the negotiations were conducted in an arm's length manner, including retaining Dr. Boothe. Dr. Boothe was present to witness the negotiations with all the short-listed bidders, including Palomar, to see that all competitors were treated fairly. SDG&E therefore requests that the Commission find that the RFP process was conducted in a way that did not favor or benefit its affiliate, SER.

SER as the other party at the negotiating table for Palomar also asserts that the RFP process was conducted fairly. SER, in fact, finds it "interesting and alarming" that TURN/UCAN's witness Woodruff would be suspicious of the SDG&E/SER negotiations just because of the affiliate relationship between the parties-even though Woodruff had no facts to support his allegations. In fact, SER opines just the opposite: that if the ATRs had prevented SER from bidding in the RFP, SDG&E's customers would be the losers as they would have been deprived of the least cost, best fit generation resource available to meet the utility's short and long-term reliability needs.

In D.04-01-050, the Commission adopted what it refers to as a "permanent ban on affiliate transactions for procurement" subject to three exceptions.³⁴ However, in that decision the Commission noted that "SDG&E's RFP is before us as a separate matter and is not addressed herein."³⁵ SDG&E therefore takes the position that its RFP was exempted from the ban on affiliate transactions contracts, and states that this interpretation is not disputed by ORA or TURN/UCAN.

3. Conclusion

We find that the record supports authorizing SDG&E to purchase Palomar from SER as a utility-owned generation asset. To begin, the turn-key project allows the utility to own a large [over 500 MWs], combined-cycle environmentally friendly, technologically advanced generation facility, with an expected useful life of 30-years. With its water-cooled system, Palomar can produce clean, efficient power, at a very low heat rate. In addition, Palomar's locationally superiority, in SDG&E's urbanized customer load center, reduces potential system losses and avoids the necessity of extensive transmission upgrades. Therefore, when evaluated against other bidders, Palomar emerged as the least cost/best fit option for serving SDG&E's short-term and long-term reliability needs.

We also find that the record shows that SER's participation in the RFP, and the subsequent negotiations between SER and SDG&E that resulted in the Palomar contract, were not a violation of the ATRs and are not covered by the ban on procurement transactions. The testimony of SER and SDG&E's witnesses supports the claim that the negotiations between the utility and its affiliate were conducted at "arms-length," each was represented by its own counsel, business and technical experts, strict confidentiality was kept, and Dr. Boothe observed the entire process and submitted a report on his observations. When these factors are weighed in toto, we find that the affiliate relationship does not dilute the least cost/best fit analysis and we approve this Palomar acquisition as being in the best interest of the SDG&E consumers and ratepayers.

We understand TURN/UCAN's arguments that the Palomar contract price was "above-market" and does not reflect the fact that it should be valued as a "distressed asset." However, we see nothing in the record to indicate that SDG&E did not negotiate in good faith to achieve the best price possible for the asset.

For the same reasons as for the Ramco proposal, we approve the cost recovery, ratemaking and revenue require proposals that SDG&E requested for Palomar. Specifically, we approve a 50-basis-point adder on the ROE that will apply to the Palomar facility once SDG&E has acquired, and is operating, it as a utility-owned generation asset, and we also approve the initial revenue requirement and the ratemaking process that SDG&E has proposed for Palomar.

We also approve SDG&E's proposed heat rate incentive for Palomar. This incentive will encourage SDG&E to operate the facility, once it is operational, in the most efficient manner, so as to benefit both SDG&E's ratepayers and its shareholders. We therefore authorize SDG&E to record any accrued incentive rewards or penalties associated with the operation of Palomar, once it is operational, in SDG&E's ERRA.

TURN/UCAN raise one other point that needs addressing: SER's contract with DWR. TURN/UCAN request that we condition approval of the Palomar proposal on SER renegotiating its contract with DWR to provide ratepayer savings. However, there is no basis in the record before us to impose such a condition, and we decline to do so. SDG&E is nonetheless encouraged to do anything it can in regards to renegotiating DWR contracts for the benefit of its ratepayers.

E. Otay Mesa

Otay Mesa is a natural gas-fired combined-cycle power plant currently under construction by Calpine. The facility is located "on-system" in SDG&E's service area, approximately 15 miles southeast of downtown San Diego. Otay Mesa will interconnect with SDG&E's electric system at the utility's Miguel Substation, will have a nominal output of 585 MW, with guaranteed baseload and peak heat rates of 6,971 and 7,230 Btu/kWh, respectively. The Otay Mesa project includes interconnection and certain network upgrade facilities comprised of a new 230 kV switchyard and loop-in of the existing Tijuana-Miguel 230 kV line, reconductoring of the Otay Mesa-Miguel line section, and various special protection devices. These upgrades are estimated to cost under $16 million and are the only project-specific transmission facilities that are part of the Otay Mesa project.

Calpine reminds the Commission, that these interconnection facilities are distinct from the SDG&E proposed Transmission System Enhancement package of additional facilities that are not specific to the Otay Mesa project and are the subject of A.04-03-008, filed by SDG&E on March 8, 2004. The projected cost for these enhancement upgrades is $127 million³⁶ and the upgrades will improve existing transmission corridors, without installing any new corridors. Calpine argues that it is important to understand that the proposed Transmission System Enhancements are not necessary for Otay Mesa to satisfy SDG&E's local reliability needs, since the facility already does that by virtue of the fact that is in SDG&E's service territory and is directly interconnected to the Miguel Substation. The Transmission System Enhancements are designed by SDG&E to maximize overall economic, planning, and reliability benefits to its customers, and in no way affected Otay Mesa's RFP eligibility.³⁷

Calpine urges the Commission to not include the Transmission System Enhancements in the assessment of the cost-effectiveness of the facility. As Calpine asserts, if these costs are to be considered in weighing the overall cost-effectiveness of Otay Mesa, then the project must also be credited with the multiplicity of system benefits the upgrades will bring, such as allowing SDG&E to realize the RMR savings and increasing the overall flexibility and reliability of its transmission and local delivery systems. As SDG&E's witness Korinek stated, these benefits will be available to SDG&E ratepayers for the expected 40-year "normal life" of these transmission facilities.³⁸ Therefore, once SDG&E ratepayers cease making payments to Otay Mesa under the 10-year PPA, ratepayers will continue to benefit from the Transmission System Enhancement for an additional 30 years.

Calpine asks the Commission to find that the Otay Mesa PPA is reasonable and in the best interest of the SDG&E ratepayers because the facility will be counted toward meeting SDG&E's local grid reliability needs upon its commencement and the prices are competitive. Calpine argues that there really is no way to compare any other facility to Otay Mesa other than Palomar, and the Otay Mesa 10-year PPA does not compare well with a utility-owned asset with a 30-year projected useful life, unless one simply compares the first 10 years of both contracts. If one does try to compare the projects, as SDG&E did, by imputing costs to Otay Mesa for years 11-30, this methodology favors a utility-owned facility. Calpine posits that however one compares prices, Otay is still a good bargain. Calpine also argues that no consideration was given in comparing prices to the fact that Otay Mesa provides SDG&E with the opportunity to significantly reduce its RMR costs - especially considering that the increasing, escalating costs of the RMR contracts constitute a large component of SDG&E's revenue requirement. For example, in 2001 SDG&E's total RMR costs were $30 million; in 2003, they were $80 million, and in 2004, FERC authorized an RMR revenue requirement of $110 million.³⁹ Calpine explains that SDG&E's RMR costs have been escalating because increases in electric demand causes increases in both total RMR megawatts and in the average cost of the RMR megawatts. New generation from Palomar and Otay Mesa will allow SDG&E to deliver both reduced RMR capacity and reduced RMR energy costs. When Palomar and Otay Mesa are dispatched for RMR capacity, that will reduce the time the more expensive older units will be dispatched, and the RMR energy prices will be reduced to reflect the lower operating costs of these more efficient units.

TURN/UCAN challenge both the need for the Otay Mesa facility, and the terms of the PPA. To begin, TURN/UCAN question whether SDG&E has provided a sufficient showing of need, for a particular time period, and for a precise amount of MWs. In response to that criticism, Calpine retorts, TURN/UCAN take a "minimalist resource procurement strategy." Calpine opines that this strategy leaves SDG&E at risk if there is another exigent energy situation.

In addition, TURN/UCAN inquire about a Calpine offer to "provide capacity from the Otay Mesa Project for a 10-year term at a price that constitutes 95% of the cost to SDG&E ratepayers over such 10-year term" of any comparable bona fide offer.⁴⁰ TURN/UCAN question why this provision was not part of the PPA, and Calpine argues that the 95% was but one offer, and it never obligated itself to keep that 95% option available.

Calpine also asserts that it is not appropriate in evaluating the cost of the Otay Mesa PPA to compare it to the Mountainview PPA approved for Southern California Edison Company in D.03-12-059. Mountainview had an attractive, below-market sales price, because it was a distressed asset and a significant portion of the sunk costs was not passed on in the sales price. However, as Calpine argues, Mountainview is not without its attendant problems and potential risks due to its FERC jurisdictional PPA, factors that are not a consideration with the Otay Mesa PPA.

TURN/UCAN are not the only parties presenting opposition to the Otay Mesa proposal. ORA also has reservations about the project and recommends that the Commission reject it, because Palomar is a superior deal for ratepayers, and Palomar fills the need for that amount of capacity. ORA does not see the need for SDG&E to have contracts with both Palomar and Otay Mesa. Although Otay Mesa gives SDG&E a newer more efficient power resource with the potential for reduced RMR costs, because ORA contends that the resource is not necessary now, or in the near future, for grid reliability, ORA is concerned that it is likely to create stranded costs far exceeding the proposed RMR savings. In addition, ORA does not approve of the transmission upgrade and debt equivalency conditions SDG&E requested in connection with the approval of the PPA.

InterGen asserts that Otay Mesa does not square with the objectives or needs articulated in SDG&E's motion, the facility will not satisfy grid reliability needs in 2005-2007, the cost of the PPA can not be justified in comparison with other options, and the transmission upgrades may inadvertently impede or delay other critical transmission upgrades. Despite this litany of objections, InterGen is most concerned that if the PPA is approved, that the Commission make sure that the Otay Mesa system upgrades do not prejudice or impede any other transmission upgrades.

SER does not oppose Otay Mesa, but SER urges the Commission to approve Palomar. If that is done, SER is neutral on whether the Commission approves Otay Mesa.

Consistent with its position throughout this proceeding, Nevada Hydro opposes the Otay Mesa PPA because of the alleged special treatment the proposal received in the RFP. Nevada Hydro alleges it is unfair to other bidders, and potential bidders, to have Palomar be the winning bidder, yet have SDG&E continue negotiations with Otay Mesa when the asset was no longer needed and it failed to meet the specifications of the RFP.

PG&E's only concern in regards to Otay Mesa is that the Commission does not reallocate the DWR/Sunrise contract from SDG&E to PG&E as a condition precedent to authorizing the Otay Mesa PPA.

Celerity is also focused solely on its plea that it be allowed a contract with SDG&E, and it presents no opinion on the Otay Mesa PPA.

Dynegy and Coral do not advocate allowing SDG&E to sign with both Palomar and Otay Mesa. Dynegy argues that Otay Mesa is not needed for grid reliability and should not have been considered in the RFP when bidders others were excluded or found to be non-conforming. Dynegy urges the Commission to reopen the RFP and defer any decision on Otay Mesa until a fair and open RFP is completed. Coral claims SDG&E did not make its case that it needs both Palomar and Otay Mesa, and Otay Mesa should be deferred to the LTRP phase of the proceeding and not considered here. Coral also questions whether the benefits that SDG&E allege will inure from Otay Mesa and the new transmission upgrades might result from the transmission upgrades alone, without the cost of the Otay Mesa PPA.

a) Reasons to Approve the PPA

We have determined that SDG&E does also need Otay Mesa as we discuss further below. We accordingly approve the PPA. Approving both Palomar and Otay Mesa, along with the Comverge, Envirepel, and Ramco proposals comports with a "hedging" strategy of having various ownership situations, different pricing and contract terms, fuel diversity, as well as a mix of resources from demand reduction to renewables to generation. This concept of a mixed portfolio will ensure that SDG&E has adequate, reliable, and reasonably priced energy, including reserves, and is consistent with the Energy Action Plan, AB 57, and Pub. Util. Code § 454.5. The Energy Action Plan encourages new, cleaner, efficient power sources to meet anticipated demand growth, replace aging, less-efficient and dirty power plants both permanently and as part of RMR contract obligations so as to reduce SDG&E's RMR costs, and to achieve and maintain adequate reserve levels. The Energy Action Plan encourages the state to add new generation resources.

While we appreciate the minimalist resource procurement strategy advanced by the ratepayer and consumer groups, who advocate having new MWs match specific showing of need, we also know the lag time necessary to get a new power plant up-and-running. As of today, Palomar and Otay Mesa provide the only possible sources of new generation with capacity over 500 MW, in SDG&E's service territory, that can serve SDG&E's needs in the foreseeable future. These facilities are fully permitted, have water for cooling purposes, which helps them operate at low heat rates, and have already received the appropriate imprimatur from local and regional environmental and community groups. SDG&E's witness hypothesized that any other new generation source comparable in size to Palomar or Otay Mesa that began to germinate as a concept today would take at least four years to come on-line.

In addition to balanced resource portfolio, there is another compelling reason to approve Otay Mesa. When we balance the lessons learned from the exigent circumstances of the energy crisis with the lessons learned from the above-market DWR contracts, which are still saddling ratepayers with exorbitant costs for excess power, we find that the insurance the 10-year PPA with Otay Mesa provides for SDG&E and its ratepayers is well worth the cost of that insurance.

b) Commission Involvement

We want to address head-on some of the concerns raised by parties over the Commission's purported involvement in the Calpine/Otay Mesa PPA. We agree that we took an active interest in the Otay Mesa facility, and the chronology set forth in Calpine's brief⁴¹ supports that interest. However, there was nothing either improper or prejudicial to any party in that interest. Moreover, the implication made by certain parties during the course of the hearings that SDG&E would not have proposed a 10-year PPA with Calpine without coming under pressure from this Commission or any of its members to do so is both scurrilous and without any basis in fact.

There is no dispute that SDG&E and its customers were hit first, and hard, by the 2001 energy crisis. Therefore, the first time we had an opportunity to evaluate SDG&E' resources, we considered what steps the utility should take to try and avoid the circumstances that found it, and its customers, so vulnerable in the energy crisis.

SDG&E's application for the Valley-Rainbow project, a 500 kV Interconnection project intended to interconnect SDG&E's 230 kV system with the 500 kV system of the Southern California Edison Company (SCE), gave us that opportunity. In that proceeding, Otay Mesa was carefully scrutinized as an alternative way to the transmission project to allow the utility to meet its grid reliability needs. In fact, a key assumption we made when we denied the Valley-Rainbow project in December 2002 was that Otay Mesa would be an in-basin generating resource available and capable of satisfying SDG&E's local reliability grid capacity needs as of 2005.⁴²

In the Valley-Rainbow decision, we encouraged SDG&E to pursue a long-term contract to ensure that Otay Mesa is timely constructed.⁴³ However, petitions for rehearing and for modification of the decision were filed, and no contract negotiations were pursued while the parties awaited the Commission's decisions on the petitions.

After the Commission indicated that it was denying the petitions, Calpine filed a motion on May 9, 2003, requesting that the Commission provide the guidance and authority necessary to allow SDG&E to address its resource needs for 2005, including expediting bilateral negotiations for a long-term power purchase contract with Otay Mesa.⁴⁴

Just one week later, on May 16, 2003, SDG&E issued its RFP, and opposed Calpine's motion on the basis that the utility could best prove its resource requirements through the competitive RFP process, in lieu of bilateral contract negotiations with Calpine. In its motion, Calpine sought an expedited filing and hearing schedule, separate from the on-going procurement proceeding, and on May 30, 2003, ALJ Walwyn issued a ruling saying that the motion and comments filed in support provided "sufficient grounds for the Commission to provide the opportunity for expedited consideration of [Calpine's] request . . . if the record evidence establishes the claims made by Calpine." On June 18, 2003, ALJ Walwyn extended the dates for submission of testimony to allow "SDG&E and Calpine to explore whether there are any alternatives to litigation."

On July 3, 2003, SDG&E filed a motion to bifurcate the Otay Mesa-specific issues from the RFP and the ongoing procurement proceedings. This prompted Commissioner Peevey on July 8, 2003, to issue an Assigned Commissioner's Ruling (ACR) suspending the separate evidentiary hearings relating to the Calpine May 2003 motion, and again encouraging the parties to continue to explore non-litigation alternatives to achieve a mutually acceptable Otay Mesa PPA. Specifically, Commissioner Peevey directed SDG&E to:

". . . . seriously consider proposals in response to its RFP, or variants thereof, that include the eventual ownership by SDG&E of highly efficient, economical and environmentally superior power plants in San Diego that will provide a significant percentage of SDG&E's total electric capacity resource requirements, including peak load plus reserve margin. . . . It may be that as SDG&E reviews the conforming proposals that it has received, it identifies some hybrid of, for example, alternatives 2 [PPA] and 3 [turn-key] that provides even greater system reliability and ratepayer benefits than does any of the specific proposals responding to the RFP. . . . SDG&E is encouraged to pursue such beneficial variants of conforming proposals . . . ."

Following the issuance of this ACR, SDG&E asked conforming bidders to provide ownership alternatives to the proposals they had already offered, and in particular asked for submittal of a three-year PPA with utility ownership at the end of the PPA. In addition, SDG&E asked respondents to provide turn-key contracts or PPAs with purchase options if they had not already provided such proposals in their original bids. Respondents were instructed to submit this information to SDG&E by July 29, 2003.

The above chronology supports the fact that the Commission took an active interest in moving SDG&E forward to meet its current, near-term, and long-term anticipated demand growth, to replace aging, inefficient, and environmentally unfriendly energy sources with new, efficient, state-of-the-art facilities, not only to meet grid reliability needs but to reduce the costs of the RMR contract costs when the old facilities were used, and to work towards increasing its reserve margins. All of these goals are consistent with the State's Energy Action Plan (EAP), adopted jointly by the Commission, the California Energy Commission (CEC) and the California Power Authority (CPA) in May 2003. The plan itself recognized the risk of having over 30% of in-state generation resources being more than 40 years old, with peak demand growing about 2.4% per year, the equivalent of about three new 500 MW power plants. The EAP concludes that California needs approximately 1,200 to 1,500 MW per year of new generation resources "to meet anticipated demand growth, modernize old, inefficient and dirty power plants and achieve and maintain reserve levels in the 25-18% range." President Peevey echoed those same goals in his July 8, 2003, ACR.

c) There Was No Unfairness in the RFP Process

Certain parties have requested that we disapprove the Otay Mesa PPA because of the allegedly "unfair" process by which it was selected. However, the evidence demonstrates that there was no unfairness in the process. To the contrary, the evidence demonstrates that SDG&E engaged in an extended, arm's length series of negotiations with Calpine, resulting in a PPA that, in SDG&E's view, provides substantial benefits both to the customers of SDG&E and to the state as a whole.⁴⁵ The record shows that these negotiations were lengthy and difficult, but also that they were entirely above-board, and that the resulting agreement was satisfactory to both parties.

Given the significant weight of the policy reasons noted just above in support of our approval of the Otay Mesa PPA, we agree with SDG&E that the Otay Mesa PPA provides substantial benefits both to the customers of SDG&E and to the state as a whole. Moreover, in our view, it was reasonable for SDG&E to negotiate with Calpine in the extended and arm's length manner that it did in order to arrive at the specific Otay Mesa PPA proposal that has been presented for our approval. We cannot find that there was anything either intrinsically or apparently "unfair" in the manner in which SDG&E conducted its RFP process with regard to Otay Mesa nor was Otay Mesa accorded any "special treatment" during the course of the RFP process.

Certain parties have also contended that the selection of the Otay Mesa PPA does not square with the bidding process called for in SDG&E's RFP. However, the evidence contradicts this allegation. Calpine's initial bid during the RFP process was clearly within the scope of the RFP, and SDG&E included it in its short list of bids to pursue. SDG&E did ultimately allow the guaranteed start date for Otay Mesa to slip to January 1, 2008, for reasons that were both reasonable and to the advantage of SDG&E and its ratepayers.⁴⁶ However, the mere fact that the parties subsequently agreed for justifiable reasons that the start-up of the Otay Mesa facility could occur at a date later than originally proposed in no way suggests that that SDG&E's selection of the Otay Mesa proposal was inconsistent or out of keeping with the bidding process.

Our approval of the Otay Mesa PPA will allow a clean, new and efficient generator to be built within SDG&E's service territory. As demonstrated in the testimony of SDG&E witnesses, the Otay Mesa project has already successfully completed the long and complicated permitting process. The Otay Mesa PPA is reasonably priced, and it will help ensure that there is adequate and reliable electric power available to California electric customers. The approval of the Otay Mesa PPA will allow older units in SDG&E service territory to eventually be retired, the net effect being that electric generation within SDG&E's service territory will be much cleaner and more efficient. Moreover, our failure to approve this PPA could result in the loss of a resource that could not be replaced easily.

The foregoing statements, taken as a whole, would not be true for any of the other combined cycle or other large projects that SDG&E reviewed in the course of its RFP process. All of those other projects - Duke South Bay Unit 4, the Enpex proposal and the Nevada Hydro proposal - are either too speculative, are not far enough along in the permit review process, and/or do not provide the environmental or cost benefits that Otay Mesa will provide. Finally, InterGen, which complained that SDG&E failed to compare the Otay Mesa proposal against its own LR2 project, did not even see fit to submit a bid for this project into the RFP process, although, as SDG&E pointed out, it could have done so if its bid included a transmission line from its project site (in Mexico) directly to SDG&E's service area. We accordingly conclude that there is no substantial basis for the complaints that SDG&E's selection of the Otay Mesa proposal was inconsistent with the objectives and needs articulated by SDG&E in its RFP.

d) Consideration of Otay Mesa Should Not Be Deferred to the New LTRP Proceeding

Certain parties advocated that because of a lack of imminent need for its power output, consideration of the Otay Mesa PPA should be deferred to the new LTRP proceeding that the Commission initiated on April 1, 2004, in R.04-04-003. We note that all of the proposals that SDG&E submitted for our approval match SDG&E's LTRP filed on April 15, 2003 in this docket, R.01-10-024. That plan described SDG&E's resource needs and presented strategies for filling those needs. The strategies consisted of four different long-term portfolios. Although the resources added in the latter years of the portfolios varied, the resource additions in the years 2004 through 2007 were essentially the same. Those resources included cost-effective energy efficiency, forecasted distributed generation, cost-effective demand reduction programs, renewable power to meet the renewable portfolio standard, and the addition of new supply-side resources to meet load and planning reserves.⁴⁷

SDG&E's RFP was specifically targeted at obtaining such resources. SDG&E's recommended contracts resulting from its RFP include a demand response program, a renewable power program, and various supply side resources. These resources additions make sense for SDG&E, because they represent resources that are needed in all of the proposed long-term resource plan portfolios presented in R.01-10-024,⁴⁸ although the exact start date and size levels necessarily differ slightly from those portfolios.⁴⁹ Moreover, all of the resources that SDG&E's has proposed for our approval are consistent with the various LTRP portfolios that SDG&E has previously submitted, in that they help meet customers' long-term energy and capacity needs while making sure that SDG&E's grid reliability criteria for 2005 through 2007 is met.⁵⁰ Thus, there is in our view no conflict between any previous LTRP that SDG&E submitted in the past and the Decision we are issuing today.

We therefore conclude that there is no need for us to defer our consideration of the Otay Mesa PPA to the newly initiated R.04-04-003. In that proceeding, the utilities will be called upon to submit new proposed LTRPs. We have every expectation that the LTRP to be proposed by SDG&E in the context of the new LTRP proceeding will be fully consistent with this decision.

e) SDG&E's Need for Otay Mesa Power

The record shows that Otay Mesa will not address SDG&E's short-term needs, 2005-2007, and SDG&E's obligations under the PPA do not even start until January 1, 2008. A number of the parties have argued that there is not clear and compelling evidence that SDG&E even needs the power from Otay Mesa to meet grid reliability needs until other contracts, specifically DWR contracts, expire in 2010. These parties argue that SDG&E really does not need Otay Mesa for the first three years of the ten-year PPA. While SDG&E would be able to utilize the power from Otay Mesa during the 2008 through 2010 period by retiring old, inefficient, dirty power sources and using Otay Mesa in lieu of existing plants that are currently operating under RMR contracts, it appears that SDG&E does not absolutely need the power from Otay Mesa during that period.

However, as discussed above, to reject Otay Mesa now, and risk that Calpine will not build the facility absent a contract with SDG&E, puts SDG&E in jeopardy of not having the plant on-line when it is needed, and the associated costs of building a 500 plus MW facility in the future are sure to exceed the costs of the build-out of Otay Mesa today. We are, moreover, aware that a significant amount of SDG&E's load demand is met by larger old units currently operating within SDG&E's service territory. These units are under no contractual obligation to remain in service, other than pursuant to annually renewable RMR contracts, and given the recent determination by owners of such older plants elsewhere in the state to furlough or shut their facilities down, there is a real risk that SDG&E could be short of power as soon as 2008 without Otay Mesa. In addition, if any of the current DWR contracts were no longer delivering power to SDG&E, the utility would need the power from Otay Mesa sooner, and closer to its on-line date of 2008.

Again, we are faced with the need to be provident when we are not prescient. We accordingly find that approving the Otay Mesa PPA is the provident and prudent thing for us to do.

f) The Benefits of a 10-Year PPA

Numerous arguments were made that Palomar, as a utility-owned generation asset with a life expectancy of 30-years, is superior to Otay Mesa with a 10-year PPA. However, little consideration was given to the benefits of the PPA arrangement. TURN/UCAN, in particular, espouse a conservative view as to asset "insurance" and the concern that the future may not mirror the present in terms of electricity needs, load growth, changing consumer markets, and advanced technology. In light of those fears, a 10-year PPA presents ratepayers with a known cost and risk, for a time period for which it is easier to posit need requirements, and reduces the risk of stranded costs resulting from unknown changes in the 11-30 year frame.

Accordingly, in our view, a 10-year PPA offers certain benefits that a 30-year arrangement cannot provide. The Otay Mesa 10-year PPA enhances the important goals of diversity in ownership, terms of contract length and ratepayer risk, which are important pieces of the complex mix of policy considerations that we must take into account in evaluating a utility's generation resource portfolio.

g) Transmission Upgrades

The Commission views the required transmission upgrades of $16 million for Otay Mesa to be necessary and reasonable. The existing transmission constraints already prevent power from being delivered within the region, and absolutely do not allow for power to be transmitted from out of state or Mexico. Our authorization of the attendant upgrades to Otay Mesa will not prejudice our consideration of any other new transmission projects or upgrades to existing ones. In particular, nothing we order in this proceeding impacts SDG&E's A.04-03-008.

We also do not consider the $127 million in proposed Transmission System Enhancements that SDG&E applied for in A.04-03-008 to be part of Otay Mesa proposal. We note that these proposed Transmission System Enhancements are not necessary for Otay Mesa to satisfy SDG&E's local reliability needs, because the Otay Mesa plant will be located within SDG&E's service territory and will directly interconnect to the Miguel Substation. We agree with Calpine that the purpose of these upgrades is to improve existing transmission corridors, and to maximize overall economic, planning, and reliability benefits to SDG&E's, and in no way affected Otay Mesa's RFP eligibility. We accordingly exclude these proposed Transmission System Enhancements from any consideration of the costs or cost-effectiveness of the Otay Mesa PPA.

h) SDG&E's Conditions

We are not ruling on two of the conditions SDG&E attached to our approval of the Otay Mesa PPA. As already discussed, the question of the requested reallocation of the DWR/Sunrise contract has been postponed pending our decision regarding cost allocation of DWR contracts in A.00-11-038 et al. Moreover, we will address the proposed Transmission System Enhancements in our consideration of SDG&E's application, A.04-03-008, including the question of whether that proceeding should be expedited.

However, we shall approve SDG&E's request for an offsetting equity adjustment to SDG&E's capital structure to recognize the debt equivalence of the Otay Mesa PPA. The proposed Otay Mesa PPA is a supply-side procurement resource that will provide firm, dispatchable capacity and energy to SDG&E's bundled service customers. For this reason, consistent with the manner in which SDG&E's existing PPA costs are recovered currently, the costs relating to Otay Mesa PPA should be recorded in SDG&E's ERRA for the purpose of recovering those costs through commodity rates (SDG&E's Schedule EECC). We also agree with SDG&E that those costs must include a return on the additional equity SDG&E must recognize to offset the debt equivalency rating agencies will assign to SDG&E as a result of the Otay Mesa PPA.

As an electricity procurement contract, the costs and expenses of the Otay Mesa PPA are subject to Public Utilities Code § 454.5, subsections (c)(1) and (d)(2). This contract results from an open and adequately subscribed auction process and is furtherance of, and consistent with, SDG&E's long-term resource plan. Therefore, once approved by the Commission, SDG&E is entitled to full recovery of the costs and expenses related to this contract and those costs and expenses are not subject to after-the-fact reasonableness reviews.

Standard & Poor's (S&P) uses the fixed-cost portion of long term PPAs as a debt equivalent, since the fixed obligation characteristics of these contracts look very similar to the fixed obligations of debt. S&P calculates this debt equivalence as the net present value of the fixed obligation (using a 10% discount rate) multiplied by a "risk factor." The risk factor can range from 0% to 100%, and S&P has assigned a 30% risk factor to SDG&E's existing long-term contracts. S&P adds this debt equivalence to other debt in its credit calculations of a utility and also imputes an associated interest expense to the value of the debt equivalence when calculating interest coverage ratios. SDG&E's evidence in this proceeding included a May 8, 2003 research report from Standard & Poor's that addressed the foregoing in substantial detail.⁵¹

TURN/UCAN acknowledged that credit rating agencies add debt equivalence for long term PPAs when evaluating a company's credit profile.⁵² However, TURN/UCAN suggested that the issue of debt equivalence related to the Calpine PPA should be considered at a later point in time in an SDG&E cost of capital proceeding. However, SDG&E has made it clear that it will not enter into the Otay Mesa PPA unless the Commission acknowledges the debt equivalence effect of this PPA and provides SDG&E the ability to adequately offset the debt equivalency effect.⁵³

We agree that SDG&E's request for the ability to accumulate equity to offset the negative impact on SDG&E's credit profile due to the Otay Mesa PPA is consistent with the general intent of AB 57, which demonstrates the Legislature's concern that the Commission not approve utility procurement plans that would somehow "lead to a deterioration of an electrical corporation's creditworthiness."⁵⁴ Consistent with this general philosophy that negative impacts to utilities' creditworthiness from procurement activities be mitigated or avoided, the Commission must address credit mitigations at the time it considers whether to approve purchase power agreements. In this case, we conclude that SDG&E's proposal to add equity to its debt/equity ratio will mitigate the negative credit impact caused by the imputed debt equivalence related to the Otay Mesa PPA and should accordingly be approved.

However, we do wish to put the parties on notice that because it has significance beyond the scope of the Otay Mesa PPA, we shall continue to monitor this question of the debt equivalence of long-term PPAs in future cost of capital proceedings.

F. The Value of This RFP Process

In summary, we observe that in approving of all five of the projects that SDG&E has submitted for our approval, including the Otay Mesa PPA, we are taking a giant step forward in the implementation of the new power procurement model that we unanimously endorsed earlier this year in D.04-01-050. This Commission has an obligation to assure that the electric utilities operating under our jurisdiction acquire sufficient generation resources to meet their customers' loads. In earlier decisions in this proceeding, such as D.02-12-074, D.03-12-062 and D.04-01-050, we have adopted short-term procurement plans and approved short-term procurement authority for SDG&E, PG&E and SCE.

However, our mandate to assure that adequate generation resources are available to these utilities' customers extends beyond the short term. In issuing its Grid Reliability RFP, SDG&E was looking beyond the short-term horizon addressed in our earlier orders. SDG&E stepped forward without any prompting from this Commission to create a first model for how longer-term power procurement proposals will be solicited, reviewed, and ultimately approved by this Commission. Based on the objections that it generated, it may be that SDG&E's handling of this first-of-its-kind RFP process was not perfect. However, it is axiomatic that the perfect is the enemy of the good, and, as is true for all new ventures, the model that SDG&E has pioneered in this case is likely to be improved upon with the benefit of experience and hindsight. Moreover, we know from long experience that any competitive bidding process involving large sums of money, where there are winners and losers, is likely to generate some protests.

Notwithstanding the procedural objections it generated, the evidence adduced in this proceeding clearly shows that the RFP process that SDG&E conducted was procedurally and legally defensible. We find that the process was open, competitive, and adequately subscribed. Moreover, we find that SDG&E's RFP process was consistent with Pub. Util. Code § 454.5(c)(1), and that the contracts and turnkey projects resulting from this RFP process, and their cost recovery and ratemaking mechanisms, will allow SDG&E to serve the needs of its customers at just and reasonable rates, will benefit consumers, and are in the public interest.

Moreover, the outcome of this RFP process not only resulted in a set of proposals for our approval that were individually meritorious, but, even more importantly, taken together, the collectivity of these five projects satisfies the complex set of policy objectives that the Legislature, as well as our own previous decisions, have mandated us to take into account in evaluating the utilities' power resource portfolios. Indeed, the successful consummation of SDG&E's Grid Reliability RFP process that is evidenced by this Decision gives us great hope and confidence that the new model for power procurement that we have been developing in this proceeding is likely to result in exactly the sort of reliable, cost-effective, balanced and environmentally sensitive electricity resource network that we have been working so hard to bring into being since the 2001 energy crisis.

G. Procedural Issues

As noted above, there were a number of procedural requests made during the course of the hearings and in post-hearing briefs and motions. One of these requests sought generic relief with respect to the RFP process; several others sought specific relief with regard to their own unsuccessful proposals; and, finally, SDG&E sought to strike portions of the briefs filed by other parties. We have determined to deny all of these requests for the reasons set forth below.

1. Dynegy Request to Re-open the RFP

Dynegy has requested that the Commission reopen the RFP and direct SDG&E to accept bids for grid reliability from existing plants that were excluded from the RFP. Dynegy also requested that the Commission defer action on Otay Mesa until the reopened RFP process.

We deny this request, because, as we stated above, we believe that the RFP process that SDG&E conducted was procedurally and legally defensible. That process was open, competitive and adequately subscribed. Moreover, that process was consistent with Pub. Util. Code § 454.5(c)(1), and the contracts and turnkey projects resulting from that RFP process, and their cost recovery and ratemaking mechanisms, will allow SDG&E to serve the needs of its customers at just and reasonable rates, will benefit consumers, and are in the public interest.

Furthermore, it was not unreasonable for SDG&E to exclude the repowering of existing plants, such as Dynegy's Encina facility, from these particular RFP process. The stated purpose of SDG&E's Grid Reliability RFP was to acquire new capacity to anticipate the grid reliability shortfall identified in SDG&E's LTRP. We note that most of Dynegy's existing Encina units operate as RMR units; as such, they must be available now and in the near future to meet the need for power within SDG&E's LRA and to help avoid the exercise of undue market power in that LRA. However, one or more of said units would have to be shut down - and be unavailable to meet local reliability needs for several years in the near term -- in order to be repowered. It may be that at some point in the future, the repowering of one or more of the Encina units would be a beneficial addition to SDG&E's generation mix. However, given the more immediate needs for which SDG&E issued its RFP, it was not unreasonable for SDG&E to exclude the repowering of units such as Dynegy's Encina facilities from the mix of potential resources for which it sought bids.

2. Nevada Hydro Request for an "Interconnect Study"

To remedy what it considered to be an "unfair" RFP, Nevada Hydro requested the Commission to require SDG&E to perform a "non-tariff" interconnect study for both the LEAPS and TE/VS Interconnection projects, at no cost to the parties, and to direct the utility to commence meaningful negotiations with the parties to create and execute contracts.

We decline to grant Nevada Hydro's request. The Nevada Hydro proposal consists of a new reservoir uphill of Lake Elsinore, a pump storage hydro-electric powerhouse and tunnels, and a transmission line interconnecting the project to both SDG&E and SCE's grid. SDG&E determined that this proposal did not conform to SDG&E RFP requirements, that it was highly speculative, and that it had very little potential for meeting an initial energy delivery deadline of June 1, 2007. Moreover, the proposal provided an interim supply for capacity that did not meet SDG&E grid reliability requirements, and the developers have no proven experience with the type of generation facility proposed or experience with undertaking engineering and construction projects of this complexity. Finally, and most important, to make delivery by June 1, 2007, the project hinged on passage of federal legislation allowing a transmission corridor across and through the Cleveland National Forest that has yet to be realized. As of the time when the hearings in this matter were held, the project developers had not applied or pursued an interconnect study agreement to: (i) determine exactly what transmission was required to interconnect with either SDG&E or SCE; and (ii) provide adequate delivery capability into SDG&E. In addition, the cost estimates provided to date by the project developers have been extremely questionable, making the project appear infeasible simply on a cost basis.

SDG&E performed substantial research to determine the feasibility of this project, particularly its ability to come on-line in or before 2007. Unfortunately, the schedule SDG&E received from the project developers was outdated from the time of receipt because several of the due dates had come and gone. SDG&E consulted the FERC database for this project to see how it was progressing through FERC. However, the project developers only submitted an application for a FERC license for their project within the last two months. And, in that FERC license application, the developers show two reservoir sites located in national forest land for which environmental impact statements have yet to be prepared. None of the final designs for the dam, the powerhouse, the tunnels or the penstock have been completed. Therefore, as testified by SDG&E witness Thomas, SDG&E does not expect this project to come to fruition, if at all, until at least 2009.⁵⁵

On top of that, there is a new transmission line that must be sited, constructed and in operation in order for the project to be feasible. That transmission line is, as represented by the attorney for Nevada Hydro, similar to SDG&E's rejected Valley-Rainbow 500 kV Interconnection proposal.

3. Celerity Request for Clarification

Celerity has asked the Commission to clarify the single sentence in the Vision Statement that the PRG members seized on to recommend disqualification of the Celerity proposal, and to indicate that this language should not be interpreted to disqualify Celerity's proposal from consideration as a demand reduction product. Celerity also asks us to authorize SDG&E to complete negotiations of a contract with Celerity.

We decline to grant any of Celerity's requests. A key element of the Celerity proposal was the conversion of existing customer-owned diesel backup generation units to dual-fueled units that primarily burn natural gas, to install necessary emission controls, and to install software and communications equipment allowing the utility to dispatch all of some of these resources within short notice, thereby allowing the customer owning those backup units to drop load from the utility grid while continuing their business and operations.

We agree with those members of the PRG who determined that the Celerity proposal did not meet the technical definition of demand response. As the Vision Statement attached to Commission Decision D.03-06-032 made clear, demand response "does not include or encourage switching to use of fossil-fueled emergency back-up generation. . . " There can be no reasonable doubt that the Celerity proposal was largely a matter of "switching to the use of fossil-fueled emergency back-up generation."

However, SDG&E also evaluated Celerity's ostensible "demand response" proposal as a supply-side proposal, but considered the Celerity proposal to be unacceptable as a supply-side contract, because it was not economic when compared to alternative supply-side resources. The Celerity proposal consisted of gas-fired generation with a very low capacity factor (60-250 hours per year) and a heat rate of 11,000 BTU per kWh. This capacity factor is much lower than a conventional peaker unit, and the heat rate of the Celerity generation is much higher than modern peaking combustion turbines whose heat rate can be as low as 9,900 BTUs per kWh.⁵⁶ As a supply-side bid, the Celerity proposal was determined to be more than twice as expensive as Ramco's ten-year PPA bid for energy and capacity.

We accordingly cannot find that SDG&E erred in declining to consummate an agreement with Celerity in connection with this RFP process, and we shall not direct them to do so. As demand response programs evolve over time, there may be a place in the overall resource mix for projects, like Celerity, that involve the use of fossil-fired emergency back-up generation. However, in the immediate and near-term future, we expect demand response programs to reduce load in absolute terms, not merely to substitute utility-provided generation with dirtier and more inefficient fossil-fired generation that has the sole advantage of being customer-owned.

4. SDG&E Motion to Strike Portions of Briefs

By Motion filed on March 11, 2004, SDG&E requested that certain portions of the briefs submitted by Dynegy, TURN/UCAN, and Nevada Hydro be stricken. The basis for SDG&E's Motion was that these parties had introduced into their briefs alleged facts that were either not in the evidentiary record or that had been specifically excluded from the record by ruling of the ALJ during the course of the hearings on this matter.

On March 16, 2004, Calpine filed a Response in support of SDG&E's Motion; and on March 19 and 26, 2004, Dynegy and TURN/UCAN, respectively, filed a Responses in opposition to this Motion.

Although we are sympathetic with SDG&E's concern that alleged facts not introduced into, or excluded from, the evidence may have been relied on in the briefs in question, we are disinclined to strike the ostensibly offending portions of those briefs. To the extent that arguments in briefs submitted for this Commission's consideration rely on alleged facts not in evidence, or are based on distortions, or even gross misstatements of the relevant facts, we are well able to give such arguments little or no weight. SDG&E and Calpine have made effective arguments in their respective filings as to why the offending arguments should be ignored, and we have taken these considerations into account in reaching the decision we make today. However, we see no reason to formally strike any portions of the briefs in question, and we decline to do so.