SOUTHERN CALIFORNIA EDISON COMPANY S 2006 LONG-TERM PROCUREMENT PLAN REPLY TESTIMONY VOLUME 2 (U 338-E) Before the

Transcription

1 Rulemaking No.: R Exhibit No.: SCE-, Volume Witnesses: Robert C. Boada Gary L. Schoonyan Carl H. Silsbee Gary A. Stern (U -E) SOUTHERN CALIFORNIA EDISON COMPANY S 00 LONG-TERM PROCUREMENT PLAN REPLY TESTIMONY VOLUME Before the Public Utilities Commission of the State of California Rosemead, California April, 00

2 Southern California Edison Company's 00 Long Term Procurement Plan Reply Testimony Volume Table Of Contents Section Page Witness I. INTRODUCTION...1 II. III. SCE SUPPORTS PROPERLY-STRUCTURED CAPACITY MARKETS... A. Centralized Capacity Markets Must Be Properly Structured... B. The Market Should Allow Tradable Capacity Products... IOUS HAVE A ROLE IN NEW GENERATION... A. The Commission Should Not Abandon the Hybrid Market Structure... B. The Commission Should Adopt SCE s New Generation Proposal Utility-Owned Options Should Be Available... a) TURN s Proposal Has Merit, With Minor Modifications... b) CUE Recognizes The Value of UOG...1 c) SCE Disagrees With Aglet s Hard Target For UOG...1 d) Market Participants Fail To Recognize The Benefits of UOG...1. PPAs Cannot Be Exactly Compared to UOG...1 C. The Financial Impacts of Contracting Should Be Considered In Weighing the Benefits of UOG The Commission Should Maintain Its Existing Policy on Debt Equivalence...1 a) Debt Equivalence Belongs in Both the LTPP and Cost of Capital Proceedings...1 G. Stern R. Boada -i-

3 Southern California Edison Company's 00 Long Term Procurement Plan Reply Testimony Table Of Contents (Continued) Section Page Witness b) Use of S&P Methodology is Appropriate...0 c) Use of S&P Methodology Does Not Provide a Windfall for Investors...1 d) Current DE Methodology Does Not Overstate The Cost of PPAs Or Discourage PPA Bidders...1 e) S&P Revised Methodology Would Increase Debt Equivalence... f) Direct Correlation Exists Between Financial Ratios and Credit Ratings... g) PPA Analysis Recommendations Should Not be Made Based on Proposed Capital Spending Programs... h) Jurisdictional Rejection of S&P Methodology Leads to Sub-Optimal Contract Selection.... Collateral and Debt Equivalence Issues Contribute to the Fact That a Balanced... Portfolio of PPA and Utility Ownership is Preferred... a) Sole Reliance on the PPA Option Does Not Avoid Credit Stress... b) PPAs Increase a Utility s Cost of Capital... c) Current Collateral Requirements for PPAs Do Not Provide Asymmetric Benefit to the Utility... D. The Commission Should Eliminate the 0/0 Sharing Mechanism and Adopt Fair Cost Recovery for UOG Projects... C. Silsbee -ii-

4 Southern California Edison Company's 00 Long Term Procurement Plan Reply Testimony Table Of Contents (Continued) Section Page Witness 1. The Commission Should Eliminate the 0/0 Sharing Mechanism.... Incentive Mechanisms, If Any, Should Be Reviewed on a Case-By-Case Basis.... Cost-of-Service Ratemaking Benefits Customers...0. FEED Study Costs Should Be Recoverable...1 IV. SCE S REPOWERING PROPOSAL IS FAIR AND IT SUPPORTS THE OBJECTIVES OF AB 1 AND PRIOR COMMISSION DECISIONS... A. Overview... B. Repower Projects Do Not Have a Clear Preference in Resource Planning or Procurement... C. CAISO Must Separately Certify That the Repower Project is Needed for Local Area Reliability... D. Utilities Must Retain Responsibility For Implementing Their Own LTPPs... E. Transmission Investment Costs and Transmission Losses are Considered by SCE... F. Additional Project Certainty is Needed for a Costof-Service Transaction... G. Ten-Year Contract Versus the Life of the Asset... G. Schoonyan -iii-

5 1 1 1 I. INTRODUCTION In Volume of this Reply Testimony, Southern California Edison Company (SCE) responds to intervenors criticisms of certain policy issues raised in SCE s Long Term Procurement Plan (LTPP) and discusses certain proposals raised by other parties. 1 Volume addresses the following topics: Capacity Markets: In Section II SCE responds to testimony on capacity markets, noting that while SCE endorses capacity markets, they must be properly structured. New Generation: In Section III SCE responds to testimony opposing the hybrid market; rebuts opposition to the new generation proposal set forth in the LTPP; responds to criticism directed at the financial impacts of continuing to contract only from third parties; opposes the 0/0 sharing mechanism and discusses equitable cost recovery for new generation. Repowering: In Section IV SCE responds to various repowering proposals and explains what is necessary to implement AB 1. These issues are discussed in the sections below. 1 As in Volume 1, parties are abbreviated as follows: Aglet Consumer Alliance (Aglet); the Alliance for Retail Energy Markets (AReM); AREVA NP Inc. (Areva); Cogeneration Association of California and the Energy Producers and Users Coalition (CAC/EPUC); California Clean DG Coalition (CCDC); Calpine Corporation (Calpine); Californians for Renewable Energy, Inc. (CARE); California Cogeneration Council (CCC); California Energy Commission (CEC); Center for Energy Efficiency and Renewable Technologies (CEERT); City and County of San Francisco (CCSF); California Large Energy Consumers Association (CLECA); Constellation Energy Commodities Group, Inc.; Constellation Newenergy, Inc.; Constellation Generation Group LLC; Reliant Energy, Inc.; Mirant California, LLC; Mirant Delta, LLC; Mirant Portrero, LLC (collectively Competitive Market Advocates ) (CMA); California Municipal Utilities Association (CMUA); Constellation Energy Commodities Group, Inc.; Constellation Newenergy, Inc.; Constellation Generation Group, LLC (Constellation); Coalition of California Utility Employees (CUE); Direct Access Customer Coalition (DACC); Division of Ratepayer Advocates (DRA); The Green Power Institute (GPI); Independent Energy Producers Association (IEP); LS Power Generation LLC (LS Power); Merced Irrigation District (Merced); Mirant Portrero LLC; Mirant California; Mirant Delta LLC (Mirant); Modesto Irrigation District (Modesto); Natural Resources Defense Council (NRDC); NRG Energy Inc. (NRG); The Utility Reform Network (TURN); Utility Consumers Action Network (UCAN); Women s Energy Matters (WEM); and the Western Power Trading Forum (WPTF). 1

6 II. SCE SUPPORTS PROPERLY-STRUCTURED CAPACITY MARKETS A. Centralized Capacity Markets Must Be Properly Structured SCE noted in its LTPP that it is actively participating in the process of designing a centralized capacity market structure. NRG also supports moving to centralized capacity markets, stating, the two programs [Resource Adequacy and long-term bilateral contracts] need to be augmented with a centralized capacity clearing market to ensure the long-term viability of the California electricity markets. NRG believes that, With a capacity market in place the need for Commission mandated utility long-term procurement will be reduced and eventually replaced by market-driven incentives for long-term contracting. SCE agrees with certain of NRG s observations. We note, however, that the Commission should support and adopt a properly-structured capacity market. NRG cites the success of New England s recently-adopted Forward Capacity Market in attracting bids from new providers. SCE believes that, like New England, any successful capacity market must be run so that winning bids are determined at least four years prior to actual delivery. The forward structure of the market allows time for new generation to bid into the market, and, if its bid wins, the generator has time (several years) to construct the facility. By contrast, SCE views the current New York Capacity Market as fundamentally flawed, in that capacity commitments are not required until a month prior to delivery. Simply put, the New York market structure means that a problem is discovered only after it is too late to do anything about it (i.e., generation cannot be built in a month). NRG argues that the solution to preventing inefficient and unbalanced investment is a locational capacity market, which would positively influence investment and logical retirement SCE/Stern Vol. 1A, p.. NRG/Comnes, p., lines -1. NRG/Comnes, p., lines -. NRG/Comnes, p., lines 0-.

7 decisions by providing accurate price signals that vary by location. SCE agrees that the capacity market should be locational, that is, that capacity prices should vary by location. In larger, competitive regions this will produce the most efficient outcome. However, some locational constraints may exist within some areas where competitive outcomes are not assured. Absent sufficient competition, the market should not be allowed to set the price in these sub-regions unless bids are first mitigated, and in no event should results from the sub-regions be allowed to distort prices in larger, more competitive, regions. Moreover, in some instances, suppliers in the subregions have natural monopolies and prices they may demand must be constrained. SCE believes that a cost-based contract, such as a reliability must-run (RMR) contract, may at times be the most efficient mechanism to address these issues. In instances where there are natural monopolies, and where existing supply is needed for local reliability reasons, the California Independent System Operator (CAISO) should maintain the ability to issue RMR-like contracts. By using a capacity market that clears several years before actual delivery, new generation can compete with existing units, and, as a result, the capacity market should reduce the need for Commission mandated utility long-term procurement, as NRG observes. SCE believes, however, that a successful capacity market, especially in its early stages, requires a backstop mechanism to ensure that new, needed generation is constructed if the primary auction for some reason fails to secure this generation. Moreover, SCE believes that both the centralized capacity market, as well as this backstop role, properly reside at the CAISO, and that the rules for such a market should apply to all load within the CAISO. The simple fact is that it is the CAISO, and not the individual investorowned utilities (IOUs) or load-serving entities (LSEs), that is responsible for grid reliability. Thus, the reliability function of securing capacity properly belongs at the CAISO. NRG/Comnes, p., lines -. NRG/Comnes, pp. -, lines -1.

8 1 1 B. The Market Should Allow Tradable Capacity Products WPTF believes that the implementation of a tradable standardized capacity product would allow state policy initiatives on electricity resource adequacy and retail choice to move forward simultaneously. SCE notes that a successful centralized capacity market design will allow the bilateral trading of capacity tags. Tradable tags make it easier for buyers and sellers of any size to trade capacity. Moreover, a standardized tag simplifies contracting among parties and clarifies the obligation of both the buyer and seller, fostering greater efficiency. SCE s capacity market design incorporates this feature. Contrary to WPTF s position, however, capacity tags will not eliminate any need for a customer responsibility surcharge (CRS). Departing load customers still should be responsible for their fair share of generation costs incurred on their behalf. Moreover, as long as IOUs, with the approval or at the request of the Commission, build to meet system need on behalf of others, IOUs need explicit cost recovery, tags or no tags. WPTF/Ackerman, pp. -1, lines -. WPTF/Ackerman, p. -1.

9 III. IOUS HAVE A ROLE IN NEW GENERATION A. The Commission Should Not Abandon the Hybrid Market Structure Several intervenors argue that the hybrid market a combination of competitive market elements and traditional utility generation has failed. Some intervenors urge a more competitive market structure, with IOUs purchasing power almost exclusively through Requests for Offers (RFOs). These parties claim that: (1) SCE is attempting to orchestrate a return to a fully verticallyintegrated market structure; and () the best path is to exclude utilities from owning new generation and move to a completely deregulated market structure. CARE, by contrast, would prefer a market in which IOUs supplied their own generation to their customers. SCE disagrees with both arguments and believes that the hybrid market structure is best for California s future. The market structure endorsed by WPTF and AReM seems to be very much like the one that plagued California in , when a lack of regulation led to rampant market abuse, out-ofcontrol wholesale prices, unjust and unreasonable rates, and generation shortages during periods when there was no actual scarcity. The Commission and the State of California have recognized that, as unpleasant to theorists and ideologues as it might be, there must be some level of regulatory oversight of electricity markets. The imposition of resource adequacy requirements is just one element of the regulation that the Commission has recently implemented to stabilize electricity markets in California. At the same time, there has been clear recognition that wholesale markets can function much better than they did during the energy crisis through better market design (e.g., MRTU) and better procurement rules (forward contracting). The failures of cannot be confused with a failure of the potential for competitive wholesale markets to function well under reasonable rules and oversight. A capacity requirement, whether in the form of resource adequacy or centralized capacity markets, is a form of regulation. Coming and going rules for direct access are a form of See, e.g., WPTF/Ackerman, pp. 1- to 1-; CMA/Schnitzer, pp. -; and AReM/Mara and McClary, pp. -.

10 regulation. Must offer obligations and limitations on day-ahead schedules are forms of regulations. Price caps, whether at the current low levels in use in California, or at higher scarcity price or damage control levels, are a form of regulation. Yet, all of these forms of regulation have properly been identified as beneficial to the functioning of the market. The hybrid market is a similar form of regulation, in that a portion of the generation used to serve certain customers is regulated and the PPAs that the IOUs enter into must be compliant with Commission-approved procurement plans or reviewed for reasonableness. Accordingly, notwithstanding the alleged complexity of the hybrid market structure, it is a component of the current regulatory fabric, and the objective should be to work towards achieving the best possible hybrid market structure. SCE is not seeking a return to vertical integration. This is clearly evidenced by SCE s recent RFOs, in which SCE entered into contracts for both existing generation and new third-party generation on a large scale. While SCE s testimony describes why third-party contracting cannot work in exclusivity, and cannot work in all circumstances, there is no evidence that SCE is seeking to return to vertical integration. Indeed, there is incontrovertible evidence to the contrary. Any arguments presented by WPTF or AReM that are based on this false premise should be disregarded. It should not go unnoticed that these advocates of a so-called competitive market structure are the first ones in line to ask the Commission to impose restrictive procurement rules on LSEs (or, at least, on IOUs). Whether it be resource adequacy requirements, bidding restrictions on load in the CAISO, or obligations for public disclosure of information by IOUs in a manner that is asymmetric with requirements on other LSEs or generators, WPTF, CMA and their allies claim that these forms of regulation are in the public interest. By contrast, these entities criticize IOU ownership of generation, price caps, and offer requirements on generators as apparently anathema to a competitive market. The Commission must not be swayed by self-serving arguments to bow at the altar of socalled competition, when the buyers of power are to be excluded from the same free market and are to be governed by more restrictive rules. IEP argues that the hybrid procurement model, in which IOUs may use either utility-owned resources or third-party resources (including potentially-affiliated projects) to fill future need,

11 provides incentives for IOUs to take self-interested actions that harm ratepayers. SCE accepts that absent appropriate rules and oversight the procurement process could be affected by conflicts between the IOUs shareholders interests and the ratepayers interests, and potentially inefficient outcomes could result. What IEP fails to adequately recognize, however, is that the Commission has already put several effective safeguards in place to ensure that procurement decisions are not impacted by a potential misalignment of incentives. The required use of an Independent Evaluator whenever an IOU-affiliated project participates in a competitive solicitation is just one example of these safeguards. Extensive consultation with the Procurement Review Group a body composed primarily of Commission staff and customer advocates is another key example of a safeguard mechanism. Finally, the results of competitive solicitations for new resources, or, in the alternative, the evaluation of planned future additions whether by the IOU or through a third party are all put before the Commission for review and approval before the IOU can move forward with such projects. In summary, the oversight and regulation that IEP warns should be put in place, is already in place in the current structure. The imposition of a capacity market, as SCE advocates, would further mitigate any concerns associated with a potential misalignment of incentives. IEP also complains that SCE does not accept the principle of competition that would require IOUs to participate on a level playing field with third parties. 1 In fact, SCE has asserted that, whether we like it or not, the products offered by third parties are different from IOU-owned cost-ofservice plants, and a mere comparison of bid prices will not provide a sufficient basis for a good decision. SCE urges, instead, that in a situation where a utility project should be considered and third-party projects could also be used, SCE should be able to describe, compare, justify and recommend what it believes to be the option in the best interests of its customers. SCE s proposed process would require IOUs to determine through a competitive solicitation the best third-party options and, separately, the best utility-owned resource. The Commission, of course, would IEP/Cavicchi and Reishus, p.. 1 IEP/Cavicchi and Reishus, pp. -1.

12 ultimately decide to agree or disagree with SCE s proposal. SCE believes that it could provide the Commission with sufficient information and a recommendation upon which the Commission could act. Moreover, while SCE has described circumstances where a utility-owned project would be a valuable alternative to consider, SCE does not envision or suggest that this would typically be the case. Indeed, SCE expects that in many circumstances there would be no reason to include a utilityowned project as an alternative, and it would proceed with an exclusively third-party RFO process, as it does today. In fact, over the past several years SCE has conducted RPS, all-source, and new generation RFOs that resulted in signed contracts for many thousands of MWs of power. Utilityowned candidate projects did not participate in any of these solicitations. SCE also described some circumstances (again, those that are anticipated to be the exception, not the norm) in which it does not make sense to rely on third parties (the market) to provide the resources sought by SCE. These circumstances are described in Volume of SCE s LTPP testimony and will not be repeated here. 1 In general, these circumstances are best characterized as ones where there is no playing field at all level or otherwise; thus, IEP s criticism does not apply. Again, SCE would be seeking Commission approval to act on its recommendation, and only proceeding if it obtains that approval. While some have argued that a hybrid market should be replaced with true competition, others, such as CARE, have a different view. CARE argues for a return to a vertically-integrated structure in which all new generation would be utility-owned and provided to customers at cost-ofservice rates, and claims that market-based procurement violates the Federal Power Act. CARE is wrong. First, there is nothing in the Federal Power Act that excludes market-based rates as long as the markets are found to produce just and reasonable rates. Second, competition in wholesale markets has provided, and will continue to provide, opportunities for cost savings to ratepayers. Independent generators have proven that they are capable of building, owning and operating 1 SCE, LTPP, Vol., Section II.A.

13 generation that provides substantial benefits to consumers. Although utility ownership of generation under certain circumstances makes sense, continued procurement from third parties for substantial portions of the IOUs portfolios is warranted. B. The Commission Should Adopt SCE s New Generation Proposal 1. Utility-Owned Options Should Be Available In its LTPP, SCE made a proposal that would enable IOUs to own generation projects that will benefit their customers. SCE s proposal has received some mixed support, with some parties endorsing different rules for utility-owned generation (UOG). While TURN, for example, prefers that IOUs do a competitive solicitation first in most circumstances, TURN would allow the utility in some instances to make UOG proposals after they see bids. 1 TURN correctly recognizes that: The option of cost-based generation needs to be available to discipline the market TURN does not seek to return to the Old World in which only regulated utilities built and owned power plants, nor do we support total reliance on a volatile wholesale market to provide 0% of consumers needs for new generation. 1 This is consistent with SCE s proposal. The arguments advanced by various parties are addressed below. a) TURN s Proposal Has Merit, With Minor Modifications TURN sets out conditions under which utilities may propose self-owned generation. Certain of these are acceptable to SCE; others need modification. In TURN s view, utility-owned generation should only be proposed if it meets with one of four criteria. The first criterion is: The project was chosen in the course of a competitive solicitation. In such a case the utility s application must demonstrate that the project was superior to the other bids received, such that the PPA preference or tiebreaker was not triggered. Such a showing must include the results of the numerical analysis of the competing projects, as well as proposed ratemaking mechanisms to mitigate the cost and performance risks to ratepayers of the utility project. 1 1 TURN/Florio, pp TURN/Florio, p., lines TURN/Florio, p. 1, lines - (emphasis in original).

14 Under SCE s proposal, the utility project would not bid in the process. SCE would notify participants prior to a competitive solicitation if SCE planned on also considering a utility-owned alternative. In general, based on SCE s analysis and consideration of the total impact of the project, the utility-owned alternative would not be recommended to the Commission unless SCE believes that it is superior. SCE notes superior could include factors other than a simple net present value comparison for the reasons discussed by SCE and largely recognized by TURN. Further, SCE believes that traditional ratemaking treatment contains mechanisms to mitigate cost and performance risks to ratepayer. However, SCE may, on a case-by-case basis, propose different mechanisms. 1 The second situation in which TURN would allow UOG is: The utility had conducted a competitive solicitation within the previous twelve months and found no (or insufficient) bids to be acceptable from a ratepayer perspective. In this case the utility should not, as suggested in D.0-1-0, be required to conduct another full solicitation in order to propose an ownership option. Rather, the utility could propose a project and use the bids received in the prior solicitation as the basis for an economic comparison. Again, the utility would be required to show that its proposed project was superior to the bids received in the prior RFO, to a degree sufficient to ensure that the PPA preference or tiebreaker would not be triggered. This would include the results of the numerical analysis of the project as compared to the earlier bids, as well as proposed ratemaking mechanisms to mitigate the cost and performance risks to ratepayers of the utility project. 1 SCE finds merit in this proposal to the extent that, if a recent solicitation did not produce necessary results, the utility should be able to propose a utility-owned project shortly thereafter without the need for an additional solicitation. The third situation in which TURN would allow UOG is where: 1 SCE also specifically opposes TURN s tie breaker proposal. See Section III.B.. 1 TURN/Florio, p. 1, lines -0 (emphasis in original).

15 The project resulted from a Unique Fleeting Opportunity (UFO), such as a settlement or the buyout of a distressed asset, and provided such clearly superior results for ratepayers that a competitive solicitation would not be required to justify the project. The application proposing such a project would still need to provide an economic comparison to bids in prior RFOs, or other market data that demonstrated the superiority of the project. Once again, proposed ratemaking mechanisms to mitigate the cost and performance risks to ratepayers of the utility project should be included, to support the case for moving forward with that project in the absence of a competitive solicitation. 1 SCE agrees with TURN that the utility must have the ability to explore and quickly act on unique and fleeting opportunities. Such opportunities have the potential to provide great benefits to our customers and the Commission should provide SCE with an avenue to rapidly pursue such opportunities before they vanish. TURN would also allow new UOG where: The project was required to fulfill a specific system or portfolio need that could not reasonably be expected to be met via a competitive solicitation. In this case the utility would be required to provide a very strong showing to support moving forward without first conducting such a solicitation. In addition, the utility would have to demonstrate that the specific need for the project was sufficiently compelling to justify forcing ratepayers to bear the risks of a project that the market was not willing to provide. Ratemaking mechanisms to mitigate those risks could also be considered. 0 SCE agrees with TURN that there may be instances where portfolio need justifies utility ownership without going through the process of a competitive solicitation. One portfolio need that may support the acquisition of UOG is the balance sheet implications of contracting versus utility ownership. SCE understands TURN s term portfolio need to recognize balance sheet impacts as a possible reason for selecting UOG without a competitive solicitation. If the utility proposes a project, TURN believes that measures to mitigate initial capital cost overruns and to provide performance incentives with respect to heat rate and plant availability should be a mandatory topic for discussion in any such utility application, although not 1 TURN/Florio, pp. 1-1, lines 1- (emphasis in original). 0 TURN/Florio, p. 1, lines -1 (emphasis in original).

16 to the exclusion of other creative proposals. 1 TURN believes that Both the utility and other parties should be free to propose appropriate measures in each specific case, and the Commission should decide on a case-by-case basis the specific ratemaking treatment for that particular plant. Although on a case-by-case basis SCE could consider alternative ratemaking, the general rule should be traditional ratemaking. As a result, SCE does not support TURN s proposal to make such alternative ratemaking a mandatory topic for discussion. b) CUE Recognizes The Value of UOG CUE also sees value in a mix of UOG and contracted-for generation. CUE notes that utility ownership of generation can provide different benefits and incur different costs and risks than contracted-for generation. These differences can make utility ownership preferable to contracting in some situations. Not only does CUE believe that the option for utility-owned generation should remain open, CUE argues that the Commission should keep flexibility about the rate treatment to be applied to different generation resources. SCE agrees with CUE s conclusions. As CUE states, Utility ownership is sometimes preferable because the balance of factors, possibly but not necessarily including cost, can favor utility ownership. SCE agrees with CUE that because of the differences in risks and rewards of UOG and contracted-for generation, as well as impacts on the IOU s total generation portfolio other balance sheet impacts, UOG is sometimes preferable for reasons beyond simply costs. 1 TURN/Florio, p. 0, lines -1. TURN/Florio, p. 0, lines 1-1. CUE/Marcus, p., lines -. CUE/Marcus, p., lines -. CUE/Marcus, p., lines

17 c) SCE Disagrees With Aglet s Hard Target For UOG Aglet is perhaps the strongest supporter of UOG, advocating that the IOUs procure at least 0% of incremental long-term (ten years or more) capacity through utility-owned generation. Aglet supports its proposal by noting: 1. The percent of UOG in the IOUs portfolios is declining.. The existence of UOG in a portfolio can reduce the likelihood that suppliers will exercise market power in energy markets.. A 0% target will reduce debt equivalence costs when compared to an all contracts procurement strategy.. There are many unique benefits of UOG that cannot be quantitatively modeled. SCE agrees with Aglet that some portion of the IOUs portfolios, and the IOUs method of satisfying future needs, should consist of UOG. Moreover, SCE agrees that UOG helps address market power issues, positively impacts debt equivalence, and has many unique benefits that cannot be quantitatively modeled. SCE does not, however, support a hard target of 0% of incremental procurement. SCE believes that the need for UOG will vary from utility to utility, and will vary throughout time based on a host of considerations and circumstances. Thus, the Commission should not adopt a single hard target for any one of the utilities. d) Market Participants Fail To Recognize The Benefits of UOG As expected, other intervenors take a markedly different view. NRG does not support SCE s proposal and asks the Commission to adopt a Competitive Market First policy, in which utilities are required to demonstrate that they have solicited market alternatives before being allowed to pursue utility-build or affiliate-build turnkey options. NRG s proposed structure would prevent the IOU from taking advantage of attractive supply options. Although SCE anticipates that it will typically hold RFOs, the IOUs should have flexibility to vary from the standard course when Aglet/Reid and Weil, p., lines 1-. Aglet/Reid and Weil, pp. 1- to 1-1. NRG/Comnes, p., lines

18 necessary. IEP asserts that SCE is fundamentally rejecting a hybrid market in which the IOU can compete against third-party market alternatives for wholesale resources. Quite the contrary SCE s proposal explicitly envisions that energy will be supplied by both independent generators and by utility-owned generation. It is this mix of ownership that creates a hybrid market. IEP argues that SCE appears to assume that the marketplace cannot efficiently provide certain types of wholesale electricity products or services, but that evidence in U.S. wholesale electricity markets contradicts this assumption. 0 IEP is incorrect. SCE believes that in many situations the market can provide solutions, as evidenced by SCE s extensive use of RFOs to secure energy, capacity, and certain forms of new generation. However, we believe that for a host of reasons market-owned alternatives may not be available or viable due to unique circumstances. In addition, the associated credit, collateral, risk premiums, and other factors may make pursuing certain projects, especially very capital intensive or experimental projects, via a market-owned alternative prima facie unreasonable. CCC echoes NRG, urging the Commission to recognize there are risks as well as benefits associated with utility-owned generation. 1 While trumpeting the associated risks, CCC acknowledges that UOG provides the following benefits: flexible plant operations without additional payment for operations, full cost savings from technological improvements, cost savings from increased efficiencies of operations, Shareholder returns limited to authorized return, commission ensures that ratepayers pay only prudently-incurred costs, dedication of facility to public utility service, and avoidance of credit and counterparty risk. SCE agrees with CCC that UOG provides these benefits. However, CCC also states that, Most important, with independent generation, ratepayers pay only for power actually delivered. SCE disagrees. As CCC should IEP/Cavicchi and Reishus, p See IEP/Cavicchi and Reishus, pp CCC/Beach, pp. -. CCC/Beach, p., lines 1-1. CCC/Beach, p., lines,. 1

19 know, payments made to independent generators are contract-specific. For example, a contract may require capacity payments in which ratepayers must pay the generator without receiving any actual energy. WPTF also criticizes SCE s proposal and believes that utilities should be prohibited from bidding to provide their own generation. If utilities are to be permitted to bid their own projects, however, WPTF believes that their bids and the procurement process should be considered to be firm and not subject to any after-the-fact re-openers that would permit the utility to recover cost overruns in a manner not offered to third party suppliers. What WPTF fails to recognize, however, is that IOUs are not in the same situation as third-party suppliers. Among other things, IOU plants are dedicated to the use of their customers, as opposed to plants run solely for the benefit of an independent entity s shareholders. UOG plants can allow the IOU to take reduced output from a plant without the need to renegotiate a contract. And, unlike the independent producers, IOUs receive only a regulated rate-of-return. Moreover, despite the potential for serious harm to the IOUs, WPTF believes the Commission should make no provision to explore the reasonableness of costs incurred by the utilities: even for any risks that were unforeseen, unaddressed or inadequately mitigated, or where the manifestation of those risks could damage the utility s creditworthiness or financial stability. WPTF continues by noting, SCE then exaggeratedly suggests that were it to solely contract for the needs of its customers, the financial burden on SCE could well exceed the Company s ability to maintain its financial integrity. And, despite SCE s detailed analysis and expert witness testimony as to the potential impact of over reliance on contracting and its impact on collateral requirements, debt equivalence, and its credit rating, WPTF cavalierly claims that SCE s WPTF/Ackerman, p. -, lines -. WPTF/Ackerman, p. -, lines -1. WPTF/Ackerman, p. -, lines 1-. WPTF/Ackerman, p. -, lines 1-. 1

20 testimony is flummery. WPTF is apparently unmoved by the possibility that the State could return back to the crisis situation in , in which grid reliability hung in the balance minute by minute. Because of the financial deterioration of the utilities, there was no certainty that California would be able to secure sufficient power to prevent blackouts over large regions of the state. There was no possibility for the IOUs to sign contracts, let alone construct needed infrastructure. The Commission should disregard WPTF s comments. TURN, which has more credibility on this issue, supports the continuation of UOG options and goes as far to conclude the very fact that the risks and benefits of the two options [UOG and contracted-for generation] differ from each other supports the case for a diverse portfolio and a hybrid market structure. SCE s proposal is reasoned, measured, and provides a balance of options for future procurement. The Commission should adopt it in this proceeding.. PPAs Cannot Be Exactly Compared to UOG As noted above, SCE s proposal would not have the IOU bidding directly into a solicitation. Several parties agree with SCE that PPAs cannot be exactly compared to UOG. TURN notes that, In reality, a perfect apples-to-apples comparison between utility owned generation and PPAs is unachievable. 0 TURN recognizes that qualitative differences among the offers, especially with respect to the residual risks that will be borne by ratepayers, must be taken into account. Sometimes those factors will result in the selection of a project that is not strictly the least cost on a numeric basis because, among other things, the alternative brings with it greater ratepayer risks. 1 TURN notes that there is no simple formula that will inevitably produce the least-cost, best fit resource in every situation. TURN s comments are consistent with SCE s view that utility-owned WPTF/Ackerman, p. -, line. TURN/Florio, pp. -, lines -. 0 TURN/Florio, p., lines TURN/Florio, p., lines -1. TURN/Florio, p., lines -. 1

21 generation and contracted-for generation are fundamentally different products. SCE also agrees with TURN s witness that, although both approaches involve providing energy, potentially using similar underlying assets, the risks that ratepayers are required to take on differ substantially in the two cases the very fact that the risks and benefits of the two options differ from each other supports the case for a diverse portfolio and a hybrid market structure. Where SCE disagrees with TURN is its recommendation that this Commission should establish a preference or tiebreaker in favor of PPAs in certain situations. TURN believes that if a utility is faced with a bid for a PPA and a cost estimate for a turnkey or other utility ownership project that are very close based on an NPV analysis of the costs and benefits of each offer, the presumption is that the utility should choose the PPA. To overcome that preference, the utility must be required to make a strong showing that there were non-quantitative factors that clearly outweighed the results of the numerical analysis. The showing must go beyond a mere recitation of the pro and con factors of the two projects, and demonstrate clear ratepayer benefits as a result of the choice of the ownership option. Such a showing should include proposed ratemaking mechanisms to mitigate the cost and performance risks to ratepayers of the utility project. SCE believes that no automatic preference should be given to PPAs or to utility-owned generation. The IOU should retain the discretion to weigh each project on its merits and the Commission should not put a thumb on the scale. IEP notes that recovery of development costs is just one factor that prevents an apples-to-apples comparison of UOG and contracted-for generation. TURN/Florio, pp. -, lines 1-. TURN/Florio, pp. -, lines 1-. TURN/Florio, p., lines -. TURN/Florio, p., lines -1. 1

22 Other concerns flow from the regulatory treatment of IOU costs that can effectively function as a ratepayer subsidy to IOU bids. For example, it would be an unfair advantage to the IOU (and adverse to ratepayer interests) to permit cost recovery of IOU-as-developer costs in rates separate from the procurement process absent an adjustment in the evaluation process. Competitive developers recover costs of all bid preparation and development activities (e.g., costs associated with finding and selecting sites, site evaluations, preparatory transmission studies, etc.), including those never started or completed, through winning bids and completed projects. The price of competitive bids thus reflect development costs and the expectation of success. Thus, the evaluation of bids of the IOU-as-developer must incorporate recovery of both successful and unsuccessful development activities to be on a comparable basis with market competitors, unless the IOU and its shareholders are willing to absorb these costs. IEP simply confirms one of the many reasons UOG is a different product than third party-owned generation the costs included in the bid may be different. Under SCE s proposal, if a hybrid structure is to remain viable, the utility needs a mechanism to recover development costs and to obtain traditional cost-of-service ratemaking as the norm for new UOG. Contrary to IEP s claim, SCE has not asserted that transparency in the bid process is practically impossible. What SCE has asserted is that head-to-head comparisons of unlike products (such as utility-owned plants and third-party contracts for power) are impractical because there are too many differences in the products for the comparison to be meaningful. This is particularly true, if, as IEP proposes, the comparison is completed in the form of a simple lowest bid competitive process. IEP s call for transparency seems rooted in the notion that it is needed to ensure that utility self-build or affiliate offers are not given undue preference. When it comes to evaluation of bids, some degree of transparency in the process is useful. Sellers should have a general understanding of what buyers are seeking, so that the sellers can put forth the set of bids that fairly represents the products they have to offer. Taking transparency to an extreme, however, such as defining upfront the specific parameters that will be used to compare offers so that any party can determine the scoring of its bid, has been shown in California to have risks that exceed any claimed benefits of transparency. Using the prescribed IEP/Cavicchi and Reishus, pp. -. IEP/Cavicchi and Reishus, p.. 1

23 bid evaluation process IEP now endorses (and it is notable that they also did so during the early s in the Commission s Biennial Resource Plan Update (BRPU) process (the predecessor to today s LTPP)), can lead to bad results. BRPU, at that time, provided so much transparency that it allowed for bidders to determine how to maximize the value of their bid through the use of bid parameters that in no way represented the true costs of the units or the true cost to ratepayers of the contracts. This bid gaming would have cost ratepayers well over a billion dollars if FERC had not thrown out the auction due to an unrelated problem. C. The Financial Impacts of Contracting Should Be Considered In Weighing the Benefits of UOG 1. The Commission Should Maintain Its Existing Policy on Debt Equivalence In its LTPP testimony, SCE explains the need to continue incorporating debt equivalence impacts in evaluating power procurement contracts as part of a long-term planning framework. Debt equivalence from procurement contracts has been found by the Commission to be a recoverable cost of service to the utility. Thus, analyzing the impacts of debt equivalence as part of a long term procurement plan is appropriate. The Commission should continue to address PPA debt equivalence impacts in this proceeding and ignore requests to change its policy on debt equivalence. a) Debt Equivalence Belongs in Both the LTPP and Cost of Capital Proceedings CLECA 0 and Aglet 1 have testified that debt equivalence consideration belongs in the Cost of Capital Proceeding (COC) instead of the LTPP proceeding. This is in contradiction to prior Commission policy. The Commission has previously recognized the effects of debt equivalence in both the Cost of Capital proceedings and prior procurement plan proceedings, and should address this issue in this proceeding as a continuation of this policy. The annual Cost of D.0-1-0, mimeo, p. 1 0 CLECA/Barkovich, p.. 1 Aglet/Reid and Weil, p.. 1

24 Capital proceeding is the appropriate forum to mitigate SCE s actual debt equivalence, and the LTPP proceeding is the appropriate forum to account for the cost of debt equivalence from contracting during the planning process. Debt equivalence costs must be incorporated into any cost analysis frameworks of power procurement choices. Unless these costs are included in procurement decisions frameworks, sub-optimal resource choices are likely to be made, to the detriment of customers. b) Use of S&P Methodology is Appropriate The adjusted S&P methodology adopted by the Commission in D is an appropriate measure of debt equivalence cost and should not be revised downward or eliminated at this time. Based on that decision, the debt equivalence impacts on power procurement costs use a risk factor of 0%, rather than the % risk factor used by S&P, resulting in a lower cost impact. The fact that PPA debt equivalence is less quantifiable in the Moody s and Fitch framework does not imply that the debt equivalence cost impact can be reduced even further. Lenders look at credit ratings from all three agencies when making credit evaluations, and a ratings downgrade from any agency will have negative impacts. This is especially true if the resulting rating is below investment grade, because many investors are prohibited by their investment guidelines from holding non-investment-grade debt. SCE s current S&P rating of BBB for its unsecured debt means it is only two ratings notches away from non-investment grade, placing it at a higher risk for higher borrowing costs and higher counterparty collateral requirements. Thus, it is appropriate to include S&P s methodology as part of a comprehensive framework for determining debt equivalence impacts from procurement contracting. Additionally, as has happened in the past, rating agencies can change their views on the financial risks from contracts. An example is Moody s stance on debt equivalence. At this time, Moody s has the less restrictive approach to debt equivalence, but the firm had the more aggressive approach in the early s when it rated SCE lower than the other rating agencies. It is D.0-1-0, Conclusions of Law and (e.g., 00 COC proceeding, move to % preferred). 0

25 prudent regulatory and financial policy to include a reasonable debt equivalence value in order to avoid disadvantaging customers and IOUs. c) Use of S&P Methodology Does Not Provide a Windfall for Investors IEP asserts that a windfall for bondholders and shareholders at ratepayer expense occurs if in a cost of capital proceeding, the Commission allows for adjustment in a utility s capital structure to account for debt equivalence consistent with the utilities debt equivalence methodologies, and revenue requirements are increased as a result. IEP incorrectly argues that debt equivalence mitigation in the cost of capital proceedings provides a windfall to shareholders and bondholders. Accounting for debt equivalence-related leverage in a utility s cost of capital sets the utility s authorized return equal to the economic cost of the capital. By definition, this is not an excess return, nor by any means a windfall to investors. d) Current DE Methodology Does Not Overstate The Cost of PPAs Or Discourage PPA Bidders The 0% risk factor adopted by the Commission in D actually understates SCE s debt equivalence costs as they are currently viewed by S&P. A % risk factor would better reflect the costs associated with SCE s debt equivalence for PPAs as it is the revised risk factor used by S&P when calculating SCE s debt equivalence. However, SCE has not proposed a change in the Commission-adopted debt equivalence methodology in this proceeding. Depending on the final interpretations and evaluations of S&P s updates to its debt equivalence methodology, SCE may request an adjustment to better account for PPA debt equivalence costs during the course of this proceeding. While the current Commission-authorized methodology certainly does not overstate cost, neither does it discourage PPA bidders. PPA and utility ownership have fundamentally different characteristics and risk profiles, and it is thus not appropriate to directly compare them in an RFO forum. SCE has instead focused on maintaining a methodology that IEP/Meal, Part of, p. 0. SCE Vol.. pp

26 appropriately ranks PPA bids. The current DE methodology is necessary to determine cost rankings among competing PPA bids and, as such, should not discourage competitive bidding into an RFO. e) S&P Revised Methodology Would Increase Debt Equivalence In its November 1, 00 white paper Request For Comments: Imputing Debt To Purchased Power Obligations, S&P proposed substantial changes to its debt equivalence calculation methodology. SCE objected to many of these changes in its comments to S&P. On March 0, 00, S&P adopted changes and clarifications to its DE Policy. SCE is currently evaluating the impact on the calculation of debt equivalence from procurement contracts. It is currently estimated that the total amount of debt equivalence would actually increase, not decrease, as suggested by IEP. S&P s changes include a decrease in the discount rate from % to the imbedded cost of debt, a decrease of the risk factor from 0% to %, and modified evergreen treatment of contracts. While the decrease in the risk factor would reduce debt equivalence, the other two changes would increase debt equivalence. The application of evergreen treatment, which assumes contract terms are extended an additional 1 years, is the most impactful change. Figure III-1 below shows the difference between the current methodology and the revised methodology with and without evergreen treatment. Without evergreen treatment, and using SCE s current authorized cost of debt, the decrease in debt equivalence is only 1% in the example below. When incorporating evergreen treatment, as S&P has adopted, debt equivalence increases by 1%. While S&P also has proposed to both lower the imputed interest rate to the embedded cost of debt and include a depreciation adjustment to funds from operations, neither of these adjustments should offset the large increase in debt equivalence resulting from adoption of all of the methodology changes. S&P: Inputed Debt Calculation for U.S. Utilities Power Purchase Agreements, March 0, 00. IEP/Meal, pp., -. Evergreen treatment is assumed to be 1 years past contract expiration.