1346515

Rulemaking No.: R.06-02-013 Exhibit No.: SCE-3, Volume 2 Witnesses: Robert C. Boada Gary L. Schoonyan Carl H. Silsbee Gary A. Stern

(U 338-E)

SOUTHERN CALIFORNIA EDISON COMPANY’S 2006 LONG-TERM PROCUREMENT PLAN REPLY TESTIMONY – VOLUME 2

Before the

Public Utilities Commission of the State of California

Rosemead, California

April 9, 2007

Southern California Edison Company's 2006 Long Term Procurement Plan Reply Testimony – Volume 2

Table Of Contents Section Page Witness

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I. INTRODUCTION .............................................................................................1

II. SCE SUPPORTS PROPERLY-STRUCTURED CAPACITY MARKETS ...................................................................................2 G. Stern

A. Centralized Capacity Markets Must Be Properly Structured...............................................................................................2

B. The Market Should Allow Tradable Capacity Products..................................................................................................4

III. IOUS HAVE A ROLE IN NEW GENERATION.............................................5

A. The Commission Should Not Abandon the Hybrid Market Structure ....................................................................................5

B. The Commission Should Adopt SCE’s New Generation Proposal...............................................................................9

1. Utility-Owned Options Should Be Available ............................9

a) TURN’s Proposal Has Merit, With Minor Modifications ......................................................9

b) CUE Recognizes The Value of UOG ..........................12

c) SCE Disagrees With Aglet’s “Hard Target” For UOG .........................................................13

d) Market Participants Fail To Recognize The Benefits of UOG .................................13

2. PPAs Cannot Be Exactly Compared to UOG..........................16

C. The Financial Impacts of Contracting Should Be Considered In Weighing the Benefits of UOG....................................19 R. Boada

1. The Commission Should Maintain Its Existing Policy on Debt Equivalence ......................................19

a) Debt Equivalence Belongs in Both the LTPP and Cost of Capital Proceedings ..................................................................19

Southern California Edison Company's 2006 Long Term Procurement Plan Reply Testimony

Table Of Contents (Continued) Section Page Witness

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b) Use of S&P Methodology is Appropriate ..................................................................20

c) Use of S&P Methodology Does Not Provide a “Windfall” for Investors ..............................21

d) Current DE Methodology Does Not Overstate The Cost of PPAs Or Discourage PPA Bidders..............................................21

e) S&P Revised Methodology Would Increase Debt Equivalence...........................................22

f) Direct Correlation Exists Between Financial Ratios and Credit Ratings ............................23

g) PPA Analysis Recommendations Should Not be Made Based on Proposed Capital Spending Programs..........................24

h) Jurisdictional Rejection of S&P Methodology Leads to Sub-Optimal Contract Selection........................................................24

2. Collateral and Debt Equivalence Issues Contribute to the Fact That a Balanced....................................25

Portfolio of PPA and Utility Ownership is Preferred ..........................25

a) Sole Reliance on the PPA Option Does Not Avoid Credit Stress......................................25

b) PPAs Increase a Utility’s Cost of Capital ..........................................................................25

c) Current Collateral Requirements for PPAs Do Not Provide Asymmetric Benefit to the Utility ....................................................27

D. The Commission Should Eliminate the 50/50 Sharing Mechanism and Adopt Fair Cost Recovery for UOG Projects .................................................................................28 C. Silsbee

Southern California Edison Company's 2006 Long Term Procurement Plan Reply Testimony

Table Of Contents (Continued) Section Page Witness

-iii-

1. The Commission Should Eliminate the 50/50 Sharing Mechanism .......................................................28

2. Incentive Mechanisms, If Any, Should Be Reviewed on a Case-By-Case Basis ........................................29

3. Cost-of-Service Ratemaking Benefits Customers ................................................................................30

4. FEED Study Costs Should Be Recoverable.............................31

IV. SCE’S REPOWERING PROPOSAL IS FAIR AND IT SUPPORTS THE OBJECTIVES OF AB 1567 AND PRIOR COMMISSION DECISIONS .............................................................32 G. Schoonyan

A. Overview..............................................................................................32

B. Repower Projects Do Not Have a “Clear Preference” in Resource Planning or Procurement.............................33

C. CAISO Must Separately Certify That the Repower Project is Needed for Local Area Reliability.......................................34

D. Utilities Must Retain Responsibility For Implementing Their Own LTPPs.........................................................34

E. Transmission Investment Costs and Transmission Losses are Considered by SCE ............................................................35

F. Additional Project Certainty is Needed for a Cost-of-Service Transaction .........................................................................35

G. Ten-Year Contract Versus the Life of the Asset..................................36

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I. 1

INTRODUCTION 2

In Volume 2 of this Reply Testimony, Southern California Edison Company (SCE) responds to 3

intervenors’ criticisms of certain policy issues raised in SCE’s Long Term Procurement Plan (LTPP) and 4

discusses certain proposals raised by other parties.1 Volume 2 addresses the following topics: 5

• Capacity Markets: In Section II SCE responds to testimony on capacity markets, noting 6

that while SCE endorses capacity markets, they must be properly structured. 7

• New Generation: In Section III SCE responds to testimony opposing the hybrid market; 8

rebuts opposition to the new generation proposal set forth in the LTPP; responds to criticism 9

directed at the financial impacts of continuing to contract only from third parties; opposes the 10

50/50 sharing mechanism and discusses equitable cost recovery for new generation. 11

• Repowering: In Section IV SCE responds to various repowering proposals and explains 12

what is necessary to implement AB 1576. 13

These issues are discussed in the sections below. 14

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).

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II. 1

SCE SUPPORTS PROPERLY-STRUCTURED CAPACITY MARKETS 2

A. Centralized Capacity Markets Must Be Properly Structured 3

SCE noted in its LTPP2 that it is actively participating in the process of designing a 4

centralized capacity market structure. NRG also supports moving to centralized capacity markets, 5

stating, “the two programs [Resource Adequacy and long-term bilateral contracts] need to be 6

augmented with a centralized capacity clearing market to ensure the long-term viability of the 7

California electricity markets.”3 NRG believes that, “With a capacity market in place the need for 8

Commission mandated utility long-term procurement will be reduced and eventually replaced by 9

market-driven incentives for long-term contracting.”4 10

SCE agrees with certain of NRG’s observations. We note, however, that the Commission 11

should support and adopt a properly-structured capacity market. NRG cites the success of New 12

England’s recently-adopted “Forward Capacity Market” in attracting bids from new providers.5 13

SCE believes that, like New England, any successful capacity market must be run so that winning 14

bids are determined at least four years prior to actual delivery. The forward structure of the market 15

allows time for new generation to bid into the market, and, if its bid wins, the generator has time 16

(several years) to construct the facility. By contrast, SCE views the current New York Capacity 17

Market as fundamentally flawed, in that capacity commitments are not required until a month prior 18

to delivery. Simply put, the New York market structure means that a problem is discovered only 19

after it is too late to do anything about it (i.e., generation cannot be built in a month). 20

NRG argues that the solution to preventing “inefficient and unbalanced investment is a 21

locational capacity market, which would positively influence investment and logical retirement 22

2 SCE/Stern Vol. 1A, p. 48. 3 NRG/Comnes, p. 4, lines 10-13. 4 NRG/Comnes, p. 6, lines 8-10. 5 NRG/Comnes, p. 5, lines 20-23.

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decisions by providing accurate price signals that vary by location.”6 SCE agrees that the capacity 1

market should be locational, that is, that capacity prices should vary by location. In larger, 2

competitive regions this will produce the most efficient outcome. However, some locational 3

constraints may exist within some areas where competitive outcomes are not assured. Absent 4

sufficient competition, the market should not be allowed to set the price in these sub-regions unless 5

bids are first mitigated, and in no event should results from the sub-regions be allowed to distort 6

prices in larger, more competitive, regions. Moreover, in some instances, suppliers in the sub-7

regions have natural monopolies and prices they may demand must be constrained. SCE believes 8

that a cost-based contract, such as a reliability must-run (RMR) contract, may at times be the most 9

efficient mechanism to address these issues. In instances where there are natural monopolies, and 10

where existing supply is needed for local reliability reasons, the California Independent System 11

Operator (CAISO) should maintain the ability to issue RMR-like contracts. 12

By using a capacity market that clears several years before actual delivery, new generation 13

can compete with existing units, and, as a result, the capacity market should reduce the need “for 14

Commission mandated utility long-term procurement,” as NRG observes.7 SCE believes, however, 15

that a successful capacity market, especially in its early stages, requires a backstop mechanism to 16

ensure that new, needed generation is constructed if the primary auction for some reason fails to 17

secure this generation. Moreover, SCE believes that both the centralized capacity market, as well as 18

this backstop role, properly reside at the CAISO, and that the rules for such a market should apply to 19

all load within the CAISO. The simple fact is that it is the CAISO, and not the individual investor-20

owned utilities (IOUs) or load-serving entities (LSEs), that is responsible for grid reliability. Thus, 21

the reliability function of securing capacity properly belongs at the CAISO. 22

6 NRG/Comnes, p. 5, lines 2-5. 7 NRG/Comnes, pp. 5-6, lines 7-12.

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B. The Market Should Allow Tradable Capacity Products 1

WPTF believes that “the implementation of a tradable standardized capacity product would 2

allow state policy initiatives on electricity resource adequacy and retail choice to move forward 3

simultaneously.”8 SCE notes that a successful centralized capacity market design will allow the 4

bilateral trading of “capacity tags.” Tradable tags make it easier for buyers and sellers of any size to 5

trade capacity. Moreover, a standardized tag simplifies contracting among parties and clarifies the 6

obligation of both the buyer and seller, fostering greater efficiency. SCE’s capacity market design 7

incorporates this feature. 8

Contrary to WPTF’s position, however, capacity tags will not eliminate any need for a 9

customer responsibility surcharge (CRS).9 Departing load customers still should be responsible for 10

their fair share of generation costs incurred on their behalf. Moreover, as long as IOUs, with the 11

approval or at the request of the Commission, build to meet system need on behalf of others, IOUs 12

need explicit cost recovery, tags or no tags. 13

8 WPTF/Ackerman, pp. 3-15, lines 8-10. 9 WPTF/Ackerman, p. 3-15.

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III. 1

IOUS HAVE A ROLE IN NEW GENERATION 2

A. The Commission Should Not Abandon the Hybrid Market Structure 3

Several intervenors argue that the hybrid market – a combination of competitive market 4

elements and traditional utility generation – has failed. Some intervenors urge a “more competitive” 5

market structure, with IOUs purchasing power almost exclusively through Requests for Offers 6

(RFOs). These parties claim that: (1) SCE is attempting to orchestrate a return to a fully vertically-7

integrated market structure; and (2) the best path is to exclude utilities from owning new generation 8

and move to a completely deregulated market structure.10 CARE, by contrast, would prefer a market 9

in which IOUs supplied their own generation to their customers. SCE disagrees with both arguments 10

and believes that the hybrid market structure is best for California’s future. 11

The market structure endorsed by WPTF and AReM seems to be very much like the one that 12

plagued California in 2000-2001, when a lack of regulation led to rampant market abuse, out-of-13

control wholesale prices, unjust and unreasonable rates, and generation shortages during periods 14

when there was no actual scarcity. The Commission and the State of California have recognized 15

that, as unpleasant to theorists and ideologues as it might be, there must be some level of regulatory 16

oversight of electricity markets. The imposition of resource adequacy requirements is just one 17

element of the regulation that the Commission has recently implemented to stabilize electricity 18

markets in California. 19

At the same time, there has been clear recognition that wholesale markets can function much 20

better than they did during the energy crisis through better market design (e.g., MRTU) and better 21

procurement rules (forward contracting). The failures of 2000-2001 cannot be confused with a 22

failure of the potential for competitive wholesale markets to function well under reasonable rules and 23

oversight. A capacity requirement, whether in the form of resource adequacy or centralized capacity 24

markets, is a form of regulation. “Coming and going rules” for direct access are a form of 25

10 See, e.g., WPTF/Ackerman, pp. 1-2 to 1-6; CMA/Schnitzer, pp. 4-7; and AReM/Mara and McClary, pp. 4-7.

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regulation. “Must offer” obligations and limitations on day-ahead schedules are forms of 1

regulations. Price caps, whether at the current low levels in use in California, or at higher scarcity 2

price or damage control levels, are a form of regulation. Yet, all of these forms of regulation have 3

properly been identified as beneficial to the functioning of the market. The hybrid market is a 4

similar form of regulation, in that a portion of the generation used to serve certain customers is 5

regulated and the PPAs that the IOUs enter into must be compliant with Commission-approved 6

procurement plans or reviewed for reasonableness. Accordingly, notwithstanding the alleged 7

complexity of the hybrid market structure, it is a component of the current regulatory fabric, and the 8

objective should be to work towards achieving the best possible hybrid market structure. 9

SCE is not seeking a return to vertical integration. This is clearly evidenced by SCE’s recent 10

RFOs, in which SCE entered into contracts for both existing generation and new third-party 11

generation on a large scale. While SCE’s testimony describes why third-party contracting cannot 12

work in exclusivity, and cannot work in all circumstances, there is no evidence that SCE is seeking 13

to return to vertical integration. Indeed, there is incontrovertible evidence to the contrary. Any 14

arguments presented by WPTF or AReM that are based on this false premise should be disregarded. 15

It should not go unnoticed that these advocates of a so-called “competitive market structure” 16

are the first ones in line to ask the Commission to impose restrictive procurement rules on LSEs (or, 17

at least, on IOUs). Whether it be resource adequacy requirements, bidding restrictions on load in the 18

CAISO, or obligations for public disclosure of information by IOUs in a manner that is asymmetric 19

with requirements on other LSEs or generators, WPTF, CMA and their allies claim that these forms 20

of regulation are in the public interest. By contrast, these entities criticize IOU ownership of 21

generation, price caps, and offer requirements on generators as apparently anathema to a competitive 22

market. The Commission must not be swayed by self-serving arguments to bow at the altar of so-23

called “competition,” when the buyers of power are to be excluded from the same “free market” and 24

are to be governed by more restrictive rules. 25

IEP argues that the hybrid procurement model, in which IOUs may use either utility-owned 26

resources or third-party resources (including potentially-affiliated projects) to fill future need, 27

7

provides incentives for IOUs to take self-interested actions that harm ratepayers.11 SCE accepts that 1

absent appropriate rules and oversight the procurement process could be affected by conflicts 2

between the IOUs’ shareholders’ interests and the ratepayers’ interests, and potentially inefficient 3

outcomes could result. What IEP fails to adequately recognize, however, is that the Commission has 4

already put several effective safeguards in place to ensure that procurement decisions are not 5

impacted by a potential misalignment of incentives. The required use of an Independent Evaluator 6

whenever an IOU-affiliated project participates in a competitive solicitation is just one example of 7

these safeguards. Extensive consultation with the Procurement Review Group – a body composed 8

primarily of Commission staff and customer advocates – is another key example of a safeguard 9

mechanism. Finally, the results of competitive solicitations for new resources, or, in the alternative, 10

the evaluation of planned future additions – whether by the IOU or through a third party – are all put 11

before the Commission for review and approval before the IOU can move forward with such 12

projects. In summary, the oversight and regulation that IEP warns should be put in place, is already 13

in place in the current structure. The imposition of a capacity market, as SCE advocates, would 14

further mitigate any concerns associated with a potential misalignment of incentives. 15

IEP also complains that SCE does not accept the principle of competition that would require 16

IOUs to participate on a level playing field with third parties.12 In fact, SCE has asserted that, 17

whether we like it or not, the products offered by third parties are different from IOU-owned cost-of-18

service plants, and a mere comparison of bid prices will not provide a sufficient basis for a good 19

decision. SCE urges, instead, that in a situation where a utility project should be considered and 20

third-party projects could also be used, SCE should be able to describe, compare, justify and 21

recommend what it believes to be the option in the best interests of its customers. SCE’s proposed 22

process would require IOUs to determine through a competitive solicitation the best third-party 23

options and, separately, the best utility-owned resource. The Commission, of course, would 24

11 IEP/Cavicchi and Reishus, p. 3. 12 IEP/Cavicchi and Reishus, pp. 11-12.

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ultimately decide to agree or disagree with SCE’s proposal. SCE believes that it could provide the 1

Commission with sufficient information and a recommendation upon which the Commission could 2

act. 3

Moreover, while SCE has described circumstances where a utility-owned project would be a 4

valuable alternative to consider, SCE does not envision or suggest that this would typically be the 5

case. Indeed, SCE expects that in many circumstances there would be no reason to include a utility-6

owned project as an alternative, and it would proceed with an exclusively third-party RFO process, 7

as it does today. In fact, over the past several years SCE has conducted RPS, all-source, and new 8

generation RFOs that resulted in signed contracts for many thousands of MWs of power. Utility-9

owned candidate projects did not participate in any of these solicitations. 10

SCE also described some circumstances (again, those that are anticipated to be the exception, 11

not the norm) in which it does not make sense to rely on third parties (the market) to provide the 12

resources sought by SCE. These circumstances are described in Volume 2 of SCE’s LTPP 13

testimony and will not be repeated here.13 In general, these circumstances are best characterized as 14

ones where there is no “playing field” at all – level or otherwise; thus, IEP’s criticism does not 15

apply. Again, SCE would be seeking Commission approval to act on its recommendation, and only 16

proceeding if it obtains that approval. 17

While some have argued that a hybrid market should be replaced with “true” competition, 18

others, such as CARE, have a different view. CARE argues for a return to a vertically-integrated 19

structure in which all new generation would be utility-owned and provided to customers at cost-of-20

service rates, and claims that market-based procurement violates the Federal Power Act. CARE is 21

wrong. First, there is nothing in the Federal Power Act that excludes market-based rates as long as 22

the markets are found to produce “just and reasonable” rates. Second, competition in wholesale 23

markets has provided, and will continue to provide, opportunities for cost savings to ratepayers. 24

Independent generators have proven that they are capable of building, owning and operating 25

13 SCE, LTPP, Vol. 2, Section II.A.

9

generation that provides substantial benefits to consumers. Although utility ownership of generation 1

under certain circumstances makes sense, continued procurement from third parties for substantial 2

portions of the IOUs’ portfolios is warranted. 3

B. The Commission Should Adopt SCE’s New Generation Proposal 4

1. Utility-Owned Options Should Be Available 5

In its LTPP, SCE made a proposal that would enable IOUs to own generation projects 6

that will benefit their customers. SCE’s proposal has received some mixed support, with some 7

parties endorsing different rules for utility-owned generation (UOG). While TURN, for example, 8

prefers that IOUs do a competitive solicitation first in “most circumstances,” TURN would allow the 9

utility in some instances to make UOG proposals after they see bids.14 TURN correctly recognizes 10

that: “The option of cost-based generation needs to be available to discipline the market…TURN 11

does not seek to return to the ‘Old World’ in which only regulated utilities built and owned power 12

plants, nor do we support total reliance on a volatile wholesale market to provide 100% of 13

consumers’ needs for new generation.”15 This is consistent with SCE’s proposal. The arguments 14

advanced by various parties are addressed below. 15

a) TURN’s Proposal Has Merit, With Minor Modifications 16

TURN sets out conditions under which utilities may propose self-owned 17

generation. Certain of these are acceptable to SCE; others need modification. In TURN’s view, 18

utility-owned generation should only be proposed if it meets with one of four criteria. The first 19

criterion is: 20

The project was chosen in the course of a competitive solicitation. In 21 such a case the utility’s application must demonstrate that the project was 22 superior to the other bids received, such that the PPA “preference” or 23 “tiebreaker” was not triggered. Such a showing must include the results of 24 the numerical analysis of the competing projects, as well as proposed 25 ratemaking mechanisms to mitigate the cost and performance risks to 26 ratepayers of the utility project.16 27

14 TURN/Florio, pp. 15 – 21. 15 TURN/Florio, p. 5, lines 7-15. 16 TURN/Florio, p. 16, lines 3-8 (emphasis in original).

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Under SCE’s proposal, the utility project would not “bid” in the process. SCE 1

would notify participants prior to a competitive solicitation if SCE planned on also considering a 2

utility-owned alternative. In general, based on SCE’s analysis and consideration of the total impact 3

of the project, the utility-owned alternative would not be recommended to the Commission unless 4

SCE believes that it is “superior.” SCE notes “superior” could include factors other than a simple 5

net present value comparison for the reasons discussed by SCE and largely recognized by TURN. 6

Further, SCE believes that traditional ratemaking treatment contains mechanisms to “mitigate cost 7

and performance risks to ratepayer.” However, SCE may, on a case-by-case basis, propose different 8

mechanisms.17 9

The second situation in which TURN would allow UOG is: 10

The utility had conducted a competitive solicitation within the 11 previous twelve months and found no (or insufficient) bids to be 12 acceptable from a ratepayer perspective. In this case the utility should 13 not, as suggested in D.04-12-048, be required to conduct another full 14 solicitation in order to propose an ownership option. Rather, the utility 15 could propose a project and use the bids received in the prior solicitation 16 as the basis for an economic comparison. Again, the utility would be 17 required to show that its proposed project was superior to the bids received 18 in the prior RFO, to a degree sufficient to ensure that the PPA 19 “preference” or “tiebreaker” would not be triggered. This would include 20 the results of the numerical analysis of the project as compared to the 21 earlier bids, as well as proposed ratemaking mechanisms to mitigate the 22 cost and performance risks to ratepayers of the utility project.18 23

SCE finds merit in this proposal to the extent that, if a recent solicitation did 24

not produce necessary results, the utility should be able to propose a utility-owned project shortly 25

thereafter without the need for an additional solicitation. 26

The third situation in which TURN would allow UOG is where: 27

17 SCE also specifically opposes TURN’s “tie breaker” proposal. See Section III.B.2. 18 TURN/Florio, p. 16, lines 9-20 (emphasis in original).

11

The project resulted from a Unique Fleeting Opportunity (UFO), such 1 as a settlement or the buyout of a distressed asset, and provided such 2 clearly superior results for ratepayers that a competitive solicitation would 3 not be required to justify the project. The application proposing such a 4 project would still need to provide an economic comparison to bids in 5 prior RFOs, or other market data that demonstrated the superiority of the 6 project. Once again, proposed ratemaking mechanisms to mitigate the cost 7 and performance risks to ratepayers of the utility project should be 8 included, to support the case for moving forward with that project in the 9 absence of a competitive solicitation.19 10

SCE agrees with TURN that the utility must have the ability to explore and 11

quickly act on unique and fleeting opportunities. Such opportunities have the potential to provide 12

great benefits to our customers and the Commission should provide SCE with an avenue to rapidly 13

pursue such opportunities before they vanish. 14

TURN would also allow new UOG where: 15

The project was required to fulfill a specific system or portfolio need 16 that could not reasonably be expected to be met via a competitive 17 solicitation. In this case the utility would be required to provide a very 18 strong showing to support moving forward without first conducting such a 19 solicitation. In addition, the utility would have to demonstrate that the 20 specific need for the project was sufficiently compelling to justify forcing 21 ratepayers to bear the risks of a project that the market was not willing to 22 provide. Ratemaking mechanisms to mitigate those risks could also be 23 considered.20 24

SCE agrees with TURN that there may be instances where portfolio need 25

justifies utility ownership without going through the process of a competitive solicitation. One 26

portfolio need that may support the acquisition of UOG is the balance sheet implications of 27

contracting versus utility ownership. SCE understands TURN’s term “portfolio need” to recognize 28

balance sheet impacts as a possible reason for selecting UOG without a competitive solicitation. 29

If the utility proposes a project, TURN believes that measures to mitigate 30

initial capital cost overruns and to provide performance incentives with respect to heat rate and plant 31

availability should be a “mandatory topic” for discussion in any such utility application, although not 32

19 TURN/Florio, pp. 16-17, lines 21-6 (emphasis in original). 20 TURN/Florio, p. 17, lines 7-14 (emphasis in original).

12

to the exclusion of other creative proposals.21 TURN believes that “Both the utility and other parties 1

should be free to propose appropriate measures in each specific case, and the Commission should 2

decide on a case-by-case basis the specific ratemaking treatment for that particular plant.”22 3

Although on a case-by-case basis SCE could consider alternative ratemaking, the general rule should 4

be traditional ratemaking. As a result, SCE does not support TURN’s proposal to make such 5

alternative ratemaking a “mandatory” topic for discussion. 6

b) CUE Recognizes The Value of UOG 7

CUE also sees value in a mix of UOG and contracted-for generation. CUE 8

notes that “utility ownership of generation can provide different benefits and incur different costs 9

and risks than contracted-for generation. These differences can make utility ownership preferable to 10

contracting in some situations.”23 Not only does CUE believe that the option for utility-owned 11

generation should remain open, CUE argues that the Commission should keep flexibility about the 12

rate treatment to be applied to different generation resources.24 SCE agrees with CUE’s conclusions. 13

As CUE states, “Utility ownership is sometimes preferable because the balance of factors, possibly 14

but not necessarily including cost, can favor utility ownership.”25 SCE agrees with CUE that 15

because of the differences in risks and rewards of UOG and contracted-for generation, as well as 16

impacts on the IOU’s total generation portfolio other balance sheet impacts, UOG is sometimes 17

preferable for reasons beyond simply costs. 18

21 TURN/Florio, p. 20, lines 11-15. 22 TURN/Florio, p. 20, lines 15-17. 23 CUE/Marcus, p. 2, lines 2-5. 24 CUE/Marcus, p. 2, lines 5-11. 25 CUE/Marcus, p. 4, lines 18-20.

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c) SCE Disagrees With Aglet’s “Hard Target” For UOG 1

Aglet is perhaps the strongest supporter of UOG, advocating that the IOUs 2

procure at least 50% of incremental long-term (ten years or more) capacity through utility-owned 3

generation.26 Aglet supports its proposal by noting: 4

1. The percent of UOG in the IOUs’ portfolios is declining. 5

2. The existence of UOG in a portfolio can reduce the likelihood that 6 suppliers will exercise market power in energy markets. 7

3. A 50% target will reduce debt equivalence costs when compared to an 8 all contracts procurement strategy. 9

4. There are many unique benefits of UOG that cannot be quantitatively 10 modeled.27 11

SCE agrees with Aglet that some portion of the IOUs’ portfolios, and the 12

IOUs’ method of satisfying future needs, should consist of UOG. Moreover, SCE agrees that UOG 13

helps address market power issues, positively impacts debt equivalence, and has many unique 14

benefits that cannot be quantitatively modeled. SCE does not, however, support a hard target of 15

“50% of incremental procurement.” SCE believes that the need for UOG will vary from utility to 16

utility, and will vary throughout time based on a host of considerations and circumstances. Thus, the 17

Commission should not adopt a single hard target for any one of the utilities. 18

d) Market Participants Fail To Recognize The Benefits of UOG 19

As expected, other intervenors take a markedly different view. NRG does not 20

support SCE’s proposal and asks the Commission to adopt a “Competitive Market First” policy, in 21

which utilities are required to demonstrate that they have solicited market alternatives before being 22

allowed to pursue utility-build or affiliate-build turnkey options.28 NRG’s proposed structure would 23

prevent the IOU from taking advantage of attractive supply options. Although SCE anticipates that 24

it will typically hold RFOs, the IOUs should have flexibility to vary from the standard course when 25

26 Aglet/Reid and Weil, p. 2, lines 21-23. 27 Aglet/Reid and Weil, pp. 1-11 to 1-12. 28 NRG/Comnes, p. 7, lines 19-21.

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necessary. IEP asserts that SCE is fundamentally rejecting “a hybrid market in which the IOU can 1

compete against third-party market alternatives for wholesale resources.”29 Quite the contrary – 2

SCE’s proposal explicitly envisions that energy will be supplied by both independent generators and 3

by utility-owned generation. It is this mix of ownership that creates a hybrid market. 4

IEP argues that SCE appears to assume that the marketplace cannot efficiently 5

provide certain types of wholesale electricity products or services, but that evidence in U.S. 6

wholesale electricity markets contradicts this assumption.30 IEP is incorrect. SCE believes that in 7

many situations the market can provide solutions, as evidenced by SCE’s extensive use of RFOs to 8

secure energy, capacity, and certain forms of new generation. However, we believe that for a host of 9

reasons market-owned alternatives may not be available or viable due to unique circumstances. In 10

addition, the associated credit, collateral, risk premiums, and other factors may make pursuing 11

certain projects, especially very capital intensive or experimental projects, via a market-owned 12

alternative prima facie unreasonable. 13

CCC echoes NRG, urging the Commission to “recognize there are risks as 14

well as benefits associated with utility-owned generation.”31 While trumpeting the associated risks, 15

CCC acknowledges that UOG provides the following benefits: flexible plant operations without 16

additional payment for operations, full cost savings from technological improvements, cost savings 17

from increased efficiencies of operations, Shareholder returns limited to authorized return, 18

commission ensures that ratepayers pay only prudently-incurred costs, dedication of facility to 19

public utility service, and avoidance of credit and counterparty risk.32 SCE agrees with CCC that 20

UOG provides these benefits. However, CCC also states that, “Most important, with independent 21

generation, ratepayers pay only for power actually delivered.”33 SCE disagrees. As CCC should 22

29 IEP/Cavicchi and Reishus, p. 12-13. 30 See IEP/Cavicchi and Reishus, pp. 16-17. 31 CCC/Beach, pp. 22-23. 32 CCC/Beach, p. 23, lines 13-18. 33 CCC/Beach, p. 23, lines 2, 3.

15

know, payments made to independent generators are contract-specific. For example, a contract may 1

require “capacity” payments in which ratepayers must pay the generator without receiving any actual 2

energy. 3

WPTF also criticizes SCE’s proposal and believes that “utilities should be 4

prohibited from bidding to provide their own generation.”34 If utilities are to be permitted to bid 5

their own projects, however, WPTF believes that their bids and the procurement process “should be 6

considered to be firm and not subject to any after-the-fact re-openers that would permit the utility to 7

recover cost overruns in a manner not offered to third party suppliers.”35 What WPTF fails to 8

recognize, however, is that IOUs are not in the same situation as third-party suppliers. Among other 9

things, IOU plants are dedicated to the use of their customers, as opposed to plants run solely for the 10

benefit of an independent entity’s shareholders. UOG plants can allow the IOU to take reduced 11

output from a plant without the need to renegotiate a contract. And, unlike the independent 12

producers, IOUs receive only a regulated rate-of-return. 13

Moreover, despite the potential for serious harm to the IOUs, WPTF believes 14

the Commission should make no provision to explore the reasonableness of costs incurred by the 15

utilities: “…even for any risks that were unforeseen, unaddressed or inadequately mitigated, or 16

where the manifestation of those risks could damage the utility’s creditworthiness or financial 17

stability.”36 WPTF continues by noting, “SCE then exaggeratedly suggests that were it to solely 18

contract for the needs of its customers, ‘the financial burden on SCE could well exceed the 19

Company’s ability to maintain its financial integrity.’ ”37 And, despite SCE’s detailed analysis and 20

expert witness testimony as to the potential impact of over reliance on contracting and its impact on 21

collateral requirements, debt equivalence, and its credit rating, WPTF cavalierly claims that SCE’s 22

34 WPTF/Ackerman, p. 3-7, lines 10-11. 35 WPTF/Ackerman, p. 3-7, lines 11-14. 36 WPTF/Ackerman, p. 3-11, lines 1-3. 37 WPTF/Ackerman, p. 3-3, lines 1- 3.

16

testimony is “flummery.”38 WPTF is apparently unmoved by the possibility that the State could 1

return back to the crisis situation in 2000-2001, in which grid reliability hung in the balance minute 2

by minute. Because of the financial deterioration of the utilities, there was no certainty that 3

California would be able to secure sufficient power to prevent blackouts over large regions of the 4

state. There was no possibility for the IOUs to sign contracts, let alone construct needed 5

infrastructure. 6

The Commission should disregard WPTF’s comments. TURN, which has 7

more credibility on this issue, supports the continuation of UOG options and goes as far to conclude 8

“the very fact that the risks and benefits of the two options [UOG and contracted-for generation] 9

differ from each other supports the case for a diverse portfolio and a hybrid market structure.”39 10

SCE’s proposal is reasoned, measured, and provides a balance of options for future procurement. 11

The Commission should adopt it in this proceeding. 12

2. PPAs Cannot Be Exactly Compared to UOG 13

As noted above, SCE’s proposal would not have the IOU bidding directly into a 14

solicitation. Several parties agree with SCE that PPAs cannot be exactly compared to UOG. TURN 15

notes that, “In reality, a perfect apples-to-apples comparison between utility–owned generation and 16

PPAs is unachievable.”40 TURN recognizes that qualitative differences among the offers, especially 17

with respect to the residual risks that will be borne by ratepayers, must be taken into account. 18

Sometimes those factors will result in the selection of a project that is not strictly the “least cost” on 19

a numeric basis because, among other things, the alternative brings with it greater ratepayer risks.41 20

TURN notes that “there is no simple formula that will inevitably produce the least-cost, best fit 21

resource in every situation.”42 TURN’s comments are consistent with SCE’s view that utility-owned 22

38 WPTF/Ackerman, p. 3-3, line 3. 39 TURN/Florio, pp. 8- 9, lines 22-2. 40 TURN/Florio, p. 7, lines 19-20. 41 TURN/Florio, p. 10, lines 7-15. 42 TURN/Florio, p. 10, lines 3-4.

17

generation and contracted-for generation are fundamentally different products. SCE also agrees with 1

TURN’s witness that, although both approaches involve providing energy, potentially using similar 2

underlying assets, “…the risks that ratepayers are required to take on differ substantially in the two 3

cases…the very fact that the risks and benefits of the two options differ from each other supports the 4

case for a diverse portfolio and a hybrid market structure.”43 5

Where SCE disagrees with TURN is its recommendation that this Commission should 6

establish a “preference” or “tiebreaker” in favor of PPAs in certain situations. TURN believes that if 7

a utility is faced with a bid for a PPA and a cost estimate for a turnkey or other utility ownership 8

project that are very close based on an NPV analysis of the costs and benefits of each offer, the 9

presumption is that the utility should choose the PPA.44 To overcome that “preference,” the utility 10

must be required to make a strong showing that there were non-quantitative factors that clearly 11

outweighed the results of the numerical analysis.45 “The showing must go beyond a mere recitation 12

of the pro and con factors of the two projects, and demonstrate clear ratepayer benefits as a result of 13

the choice of the ownership option. Such a showing should include proposed ratemaking 14

mechanisms to mitigate the cost and performance risks to ratepayers of the utility project.”46 SCE 15

believes that no automatic preference should be given to PPAs or to utility-owned generation. The 16

IOU should retain the discretion to weigh each project on its merits and the Commission should not 17

put a “thumb on the scale.” 18

IEP notes that recovery of development costs is just one factor that prevents an 19

apples-to-apples comparison of UOG and contracted-for generation. 20

43 TURN/Florio, pp. 8-9, lines 14-2. 44 TURN/Florio, pp. 10-11, lines 18-8. 45 TURN/Florio, p. 11, lines 8-10. 46 TURN/Florio, p. 11, lines 10-14.

18

Other concerns flow from the regulatory treatment of IOU costs that can 1 effectively function as a ratepayer subsidy to IOU bids. For example, it would be 2 an unfair advantage to the IOU (and adverse to ratepayer interests) to permit cost 3 recovery of IOU-as-developer costs in rates separate from the procurement 4 process absent an adjustment in the evaluation process. Competitive developers 5 recover costs of all bid preparation and development activities (e.g., costs 6 associated with finding and selecting sites, site evaluations, preparatory 7 transmission studies, etc.), including those never started or completed, through 8 winning bids and completed projects. The price of competitive bids thus reflect 9 development costs and the expectation of success. Thus, the evaluation of bids of 10 the IOU-as-developer must incorporate recovery of both successful and 11 unsuccessful development activities to be on a comparable basis with market 12 competitors, unless the IOU and its shareholders are willing to absorb these 13 costs.47 14

IEP simply confirms one of the many reasons UOG is a different product than third 15

party-owned generation – the costs included in the bid may be different. Under SCE’s proposal, if a 16

hybrid structure is to remain viable, the utility needs a mechanism to recover development costs and 17

to obtain traditional cost-of-service ratemaking as the norm for new UOG. Contrary to IEP’s claim, 18

SCE has not asserted that “transparency” in the bid process is practically impossible.48 What SCE 19

has asserted is that head-to-head comparisons of unlike products (such as utility-owned plants and 20

third-party contracts for power) are impractical because there are too many differences in the 21

products for the comparison to be meaningful. This is particularly true, if, as IEP proposes, the 22

comparison is completed in the form of a simple “lowest bid” competitive process. IEP’s call for 23

transparency seems rooted in the notion that it is needed to ensure that utility self-build or affiliate 24

offers are not given undue preference. 25

When it comes to evaluation of bids, some degree of transparency in the process is 26

useful. Sellers should have a general understanding of what buyers are seeking, so that the sellers 27

can put forth the set of bids that fairly represents the products they have to offer. Taking 28

transparency to an extreme, however, such as defining upfront the specific parameters that will be 29

used to compare offers so that any party can determine the scoring of its bid, has been shown in 30

California to have risks that exceed any claimed benefits of “transparency.” Using the prescribed 31

47 IEP/Cavicchi and Reishus, pp. 25-26. 48 IEP/Cavicchi and Reishus, p. 28.

19

bid evaluation process IEP now endorses (and it is notable that they also did so during the early 1

1990’s in the Commission’s Biennial Resource Plan Update (BRPU) process (the predecessor to 2

today’s LTPP)), can lead to bad results. BRPU, at that time, provided so much “transparency” that it 3

allowed for bidders to determine how to “maximize” the value of their bid through the use of bid 4

parameters that in no way represented the true costs of the units or the true cost to ratepayers of the 5

contracts. This bid gaming would have cost ratepayers well over a billion dollars if FERC had not 6

thrown out the auction due to an unrelated problem. 7

C. The Financial Impacts of Contracting Should Be Considered In Weighing the Benefits 8

of UOG 9

1. The Commission Should Maintain Its Existing Policy on Debt Equivalence 10

In its LTPP testimony, SCE explains the need to continue incorporating debt 11

equivalence impacts in evaluating power procurement contracts as part of a long-term planning 12

framework. Debt equivalence from procurement contracts has been found by the Commission to be 13

a recoverable cost of service to the utility.49 Thus, analyzing the impacts of debt equivalence as part 14

of a long term procurement plan is appropriate. The Commission should continue to address PPA 15

debt equivalence impacts in this proceeding and ignore requests to change its policy on debt 16

equivalence. 17

a) Debt Equivalence Belongs in Both the LTPP and Cost of Capital Proceedings 18

CLECA50 and Aglet51 have testified that debt equivalence consideration 19

belongs in the Cost of Capital Proceeding (COC) instead of the LTPP proceeding. This is in 20

contradiction to prior Commission policy. The Commission has previously recognized the effects of 21

debt equivalence in both the Cost of Capital proceedings and prior procurement plan proceedings, 22

and should address this issue in this proceeding as a continuation of this policy. The annual Cost of 23

49 D.04-12-048, mimeo, p. 144 50 CLECA/Barkovich, p. 47. 51 Aglet/Reid and Weil, p. 3.

20

Capital proceeding is the appropriate forum to mitigate SCE’s actual debt equivalence,52 and the 1

LTPP proceeding is the appropriate forum to account for the cost of debt equivalence from 2

contracting during the planning process. Debt equivalence costs must be incorporated into any cost 3

analysis frameworks of power procurement choices. Unless these costs are included in procurement 4

decisions frameworks, sub-optimal resource choices are likely to be made, to the detriment of 5

customers. 6

b) Use of S&P Methodology is Appropriate 7

The adjusted S&P methodology adopted by the Commission in D.04-12-048 8

is an appropriate measure of debt equivalence cost and should not be revised downward or 9

eliminated at this time. Based on that decision, the debt equivalence impacts on power procurement 10

costs use a risk factor of 20%, rather than the 25% risk factor used by S&P, resulting in a lower cost 11

impact. The fact that PPA debt equivalence is less quantifiable in the Moody’s and Fitch framework 12

does not imply that the debt equivalence cost impact can be reduced even further. Lenders look at 13

credit ratings from all three agencies when making credit evaluations, and a ratings downgrade from 14

any agency will have negative impacts. This is especially true if the resulting rating is below 15

investment grade, because many investors are prohibited by their investment guidelines from 16

holding non-investment-grade debt. SCE’s current S&P rating of BBB for its unsecured debt means 17

it is only two ratings notches away from non-investment grade, placing it at a higher risk for higher 18

borrowing costs and higher counterparty collateral requirements. Thus, it is appropriate to include 19

S&P’s methodology as part of a comprehensive framework for determining debt equivalence 20

impacts from procurement contracting. 21

Additionally, as has happened in the past, rating agencies can change their 22

views on the financial risks from contracts. An example is Moody’s stance on debt equivalence. At 23

this time, Moody’s has the less restrictive approach to debt equivalence, but the firm had the more 24

aggressive approach in the early 1990s when it rated SCE lower than the other rating agencies. It is 25

52 D.04-12-047, Conclusions of Law 7 and 8 (e.g., 2005 COC proceeding, move to 9% preferred).

21

prudent regulatory and financial policy to include a reasonable debt equivalence value in order to 1

avoid disadvantaging customers and IOUs. 2

c) Use of S&P Methodology Does Not Provide a “Windfall” for Investors 3

IEP asserts that a “windfall for bondholders and shareholders at ratepayer 4

expense” occurs if “in a cost of capital proceeding, the Commission allows for adjustment in a 5

utility’s capital structure to account for debt equivalence consistent with the utilities’ debt 6

equivalence methodologies, and revenue requirements are increased as a result.”53 IEP incorrectly 7

argues that debt equivalence mitigation in the cost of capital proceedings provides a “windfall” to 8

shareholders and bondholders. Accounting for debt equivalence-related leverage in a utility’s cost of 9

capital sets the utility’s authorized return equal to the economic cost of the capital. By definition, 10

this is not an excess return, nor by any means a “windfall” to investors. 11

d) Current DE Methodology Does Not Overstate The Cost of PPAs Or 12

Discourage PPA Bidders 13

The 20% risk factor adopted by the Commission in D.04-12-048 actually 14

understates SCE’s debt equivalence costs as they are currently viewed by S&P. A 25% risk factor 15

would better reflect the costs associated with SCE’s debt equivalence for PPAs as it is the revised 16

risk factor used by S&P when calculating SCE’s debt equivalence. However, SCE has not proposed 17

a change in the Commission-adopted debt equivalence methodology in this proceeding. Depending 18

on the final interpretations and evaluations of S&P’s updates to its debt equivalence methodology, 19

SCE may request an adjustment to better account for PPA debt equivalence costs during the course 20

of this proceeding. 21

While the current Commission-authorized methodology certainly does not 22

overstate cost, neither does it discourage PPA bidders. PPA and utility ownership have 23

fundamentally different characteristics and risk profiles, and it is thus not appropriate to directly 24

compare them in an RFO forum.54 SCE has instead focused on maintaining a methodology that 25 53 IEP/Meal, Part 2 of 2, p. 50. 54 SCE Vol. 2. pp. 16-17.

22

appropriately ranks PPA bids. The current DE methodology is necessary to determine cost rankings 1

among competing PPA bids and, as such, should not discourage competitive bidding into an RFO. 2

e) S&P Revised Methodology Would Increase Debt Equivalence 3

In its November 1, 2006 white paper “Request For Comments: Imputing Debt 4

To Purchased Power Obligations,” S&P proposed substantial changes to its debt equivalence 5

calculation methodology. SCE objected to many of these changes in its comments to S&P. On 6

March 30, 2007, S&P adopted changes and clarifications to its DE Policy.55 SCE is currently 7

evaluating the impact on the calculation of debt equivalence from procurement contracts. It is 8

currently estimated that the total amount of debt equivalence would actually increase, not decrease, 9

as suggested by IEP.56 S&P’s changes include a decrease in the discount rate from 10% to the 10

imbedded cost of debt, a decrease of the risk factor from 30% to 25%, and modified evergreen 11

treatment of contracts. While the decrease in the risk factor would reduce debt equivalence, the 12

other two changes would increase debt equivalence. 13

The application of evergreen treatment, which assumes contract terms are 14

extended an additional 12 years, is the most impactful change. Figure III-1 below shows the 15

difference between the current methodology and the revised methodology with and without 16

evergreen treatment.57 Without evergreen treatment, and using SCE’s current authorized cost of 17

debt, the decrease in debt equivalence is only 1% in the example below. When incorporating 18

evergreen treatment, as S&P has adopted, debt equivalence increases by 61%. While S&P also has 19

proposed to both lower the imputed interest rate to the embedded cost of debt and include a 20

depreciation adjustment to funds from operations, neither of these adjustments should offset the 21

large increase in debt equivalence resulting from adoption of all of the methodology changes. 22

55 S&P: Inputed Debt Calculation for U.S. Utilities’ Power Purchase Agreements, March 30, 2007. 56 IEP/Meal, pp. 23, 33-37. 57 Evergreen treatment is assumed to be 12 years past contract expiration.

23

The newly-adopted S&P methodology changes highlight other inherent PPA 1

risk. PPA contracts, once signed, are fixed obligations to the utility that are subject to credit risk 2

volatility in the credit markets. 3

Figure III-1 Analysis of S&P Proposed Changes to DE Methodology

Annual Capacity Payment 100,000$ 100,000$ 100,000$ Term 10 Years 10 Years 10 YearsRisk Factor 30% 25% 25%Discount Rate 10.00% 6.17% 6.17%Evergreen No No YesDebt Equivalence 184,337$ 182,529$ 296,640$ % Change from Current -1% 61%

f) Direct Correlation Exists Between Financial Ratios and Credit Ratings 4

IEP attempts to discredit the use of debt equivalence adjustments by making 5

the bold assertion that no direct correlation exists between financial ratios and credit ratings.58 This 6

is patently wrong. Among the many tools, both quantitative and qualitative, that the rating agencies 7

and investors use, ratio analysis is one of the most visible and important. For example, S&P issues 8

rating guidelines based on the three key financial ratios of Funds From Operations to Interest 9

Expense (FFO/Interest ratio), Debt as a Percent of Capitalization (Debt/Total Capital ratio), and 10

Funds From Operations to Debt Capital (FFO/Total Debt ratio). In evaluating a utility’s credit, S&P 11

calculates credit statistics including its calculation of debt equivalence, and these adjusted ratios, 12

while not the sole determinant, are an important part of the S&P rating decision making process. 13

The debt equivalence impact on SCE’s ratios is the primary reason that S&P has rated SCE’s senior 14

unsecured debt several rating levels below both Moody’s and Fitch, clearly demonstrating the 15

relationship between financial ratios and credit ratings. 16

58 IEP/Meal, pp. 31-33.

24

g) PPA Analysis Recommendations Should Not be Made Based on Proposed 1

Capital Spending Programs 2

IEP states that “all three IOUs are undertaking large capital spending 3

programs that allow them ample opportunities to add to their rate base and increase their earnings 4

accordingly, even if the IOUs spend little or nothing on generation investments.”59 Even if IEP’s 5

statement were assumed to be true, it would be completely irrelevant to the determination of PPA 6

bid ranking methodology. Additions to SCE’s balance sheet capacity from non-generation rate base 7

investments should not result in choosing to ignore the financial impacts of PPA contracting. 8

Choosing the most cost effective alternative for SCE’s ratepayers is the appropriate basis for all 9

analyses undertaken, not only in this proceeding, but in all project analyses. 10

h) Jurisdictional Rejection of S&P Methodology Leads to Sub-Optimal Contract 11

Selection 12

IEP cites three cases where regulatory agencies in other states have rejected 13

the use of S&P’s imputed debt formula to measure impact on credit quality.60 S&P is an 14

independent entity that is not controlled by any regulatory jurisdiction, and as such provides 15

unbiased opinions on credit quality. Jurisdictions may reject the use of S&P’s formula, but that has 16

not in any way prevented S&P from using this formula. Jurisdictional rejection of a methodology 17

does not fix any problems; it just ignores them. To date, the Commission has rightly recognized the 18

risk and costs of PPA debt equivalence and, given the state’s high reliance on power contracts, it 19

would be foolish to go backwards in the Commission’s evaluation policy for PPA contract impacts. 20

Along with California, other states such as Delaware, Florida,61 Nevada, New Mexico, and 21

59 IEP/Meal, p. 26, lines 14-17. 60 IEP/Meal, pp. 57-59. 61 Witness MAM includes Florida in jurisdictions that reject the S&P methodology. While Florida Public Service

Commission (FPSC) did reject the S&P methodology in bid evaluation, according to the EEI white paper, they did mitigate the DE by adjusting the FPL equity ratio “based directly on the S&P methodology for calculating imputed debt.”

25

Wisconsin are identified in an EEI white paper as recognizing PPA debt equivalence as regulatory 1

policy.62 2

2. Collateral and Debt Equivalence Issues Contribute to the Fact That a Balanced 3

Portfolio of PPA and Utility Ownership is Preferred 4

As previously testified by SCE, utility ownership and contracting differ in a number 5

of fundamental ways. These fundamental differences provide diversification benefits when 6

combined in a balanced portfolio. To this point, SCE has not analyzed what the ideal allocation may 7

be, but SCE does recognize that any level of utility ownership has its advantages in terms of 8

reduction of required collateral capacity and debt equivalence. This result is evident and should not 9

be ignored in this proceeding. 10

a) Sole Reliance on the PPA Option Does Not Avoid Credit Stress 11

IEP asserts that “[t]o the extent PPA options are used instead of utility-owned 12

options to meet generation procurement requirements, further credit stress due to additional capital 13

spending will be avoided.”63 This statement ignores the debt equivalence and collateral facility 14

requirement impacts associated with contracting as a greater comparable financial burden, assuming 15

everything else equal, to owning generation facilities.64 As discussed in SCE’s direct testimony,65 16

while Commission and legislative actions to reduce recovery risks can substantially address these 17

burdens, absent these changes PPAs, as evaluated by S&P specifically and the other rating agencies 18

in certain circumstances, decrease financial credit statistics as compared to UOG. 19

b) PPAs Increase a Utility’s Cost of Capital 20

IEP cites two studies conducted in the early 1990s that found no evidence that 21

PPAs increase a utility’s cost of capital.66 Using studies from the early nineties is analogous to 22

62 Edison Electric Institute, Understanding Debt Imputation Issues, February 13, 2007 63 IEP/Meal, pp. 18-19, lines 23-1. 64 SCE Vol. 2, pp. 37-39. 65 SCE, Vol. 2, pp. 36-37. 66 IEP/Meal, pp. 45-46.

26

comparing apples to oranges. The utility industry procurement level – and SCE’s in particular – is 1

nothing like it was in the early nineties. Considering that as late as 1995, utility-owned generation 2

accounted for over 70% of SCE’s peak capacity, power procurement did not dominate as a source of 3

customer energy and capacity like it does now with total utility ownership below 30% of peak 4

capacity. Below is Figure III-1 from SCE Volume 2, showing the decline in SCE ownership as a 5

percentage of peak capacity. This illustrates the fundamental changes that have occurred since the 6

early nineties, rendering comparisons with the risk profile from now and then meaningless. The 7

facts are that imputed debt increases a company’s leverage, while collateral facilities require 8

committing a portion of the company’s liquidity to procurement activities, both of which increase 9

the balance sheet costs of a company, thereby affecting its cost of capital. The electricity 10

marketplace since the nineties has changed considerably in its handling of counterparty credit risks, 11

as collateral was not required for purchased power agreements dating back to 1995. As we now 12

know, the market has become much more credit intensive and costs for procurement contracts 13

include both direct and indirect credit costs to secure economic value for counterparties. 14

27

Figure III-1 SCE Generation Ownership (% of Peak Capacity)67

27%20%

71%83%

0%

20%

40%

60%

80%

100%

1985 1995 2005 2016

c) Current Collateral Requirements for PPAs Do Not Provide Asymmetric 1

Benefit to the Utility 2

IEP states that “Fair bid evaluation considers all costs and all benefits of bids 3

received. The extra protection provided in PPA options with this type of collateral provides 4

ratepayers with a benefit that is not provided in a utility-owned option.”68 In addition to the fact that 5

customers will presumably pay for the cost of that protection as part of the contract price, it is 6

important to recognize that collateral requirements may occur for both parties to a PPA. Any benefit 7

SCE receives from having a counterparty post collateral is offset by the fact that SCE must not only 8

post collateral (if required) when it is “out of the money,” but must also maintain collateral facilities 9

even when the contract is “in the money” due to the fact that the position could switch based on 10

market conditions. Under utility ownership, the utility neither receives collateral nor posts collateral, 11

nor is it required to allocate liquidity to a collateral facility. Collateral requirements are a cost 12

67 Excludes DWR contracts from 2005 calculation. 68 IEP/Meal, p. 60, lines 6-8.

28

created by the change to a ratepayer-generator credit relationship from the regulatory compact credit 1

relationship between the utility and its customers. Collateral is designed to secure the risk of 2

specific counterparty contract default. Utility-owned facilities have “pooled” counterparty credit 3

risk which provides credit protection at a lower cost as compared to stand-alone bilateral PPA 4

contracts. 5

D. The Commission Should Eliminate the 50/50 Sharing Mechanism and Adopt Fair Cost 6

Recovery for UOG Projects 7

1. The Commission Should Eliminate the 50/50 Sharing Mechanism 8

In supplemental testimony, SCE explained why imposing asymmetric risk sharing on 9

the construction cost of new IOU generation projects is unreasonable and incompatible with SCE’s 10

vision of the benefits that such projects can provide to SCE’s customers.69 In D.04-12-048, the 11

Commission described a structure of “all source” solicitations, wherein participating utility projects 12

would be fully at risk for cost overruns but would return 50% of any cost underruns with ratepayers 13

(50/50 cost sharing). Subsequently, the Commission directed SCE to explore alternative cost 14

sharing possibilities with other stakeholders, and as a result of a meet and confer session, SCE 15

recommended that this issue be further addressed in this proceeding.70 SCE’s request to allow 16

supplemental testimony on the 50/50 cost sharing was granted, and a number of parties have 17

addressed this issue.71 18

DRA generally supports SCE’s proposal for elimination of the 50/50 sharing 19

mechanism as the rate treatment that should be afforded new UOG, and DRA agrees with SCE that 20

something similar to traditional cost-based rate treatment would be the preferred approach, such as 21

was granted to PG&E in D.06-06-035.72 The other groups representing small customer interests in 22

69 SCE Supplemental Testimony on Cost Recovery for New Generation, February 2, 2007, pp. 1-2. 70 See Southern California Edison Company’s Report on Sharing Mechanism Discussions, R.06-02-013, January 5,

2007. 71 Administrative Law Judge’s Ruling on Time Extension and Supplemental Testimony, January 17, 2007. 72 DRA, Vol. A, pp. 4 and 40-44, lines 16-20 and 16-11.

29

this proceeding, TURN,73 UCAN,74 and Aglet,75 also support elimination of the current 50/50 cost 1

sharing mechanism in favor of something more like traditional rate base ratemaking for utility 2

owned generation projects. 3

A number of parties would have new IOU generation projects compete on a “head-to-4

head” basis with non-utility generation projects in utility procurement RFOs. In such a 5

circumstance, 50/50 cost sharing creates an obvious unfair bias against utility proposals. To the 6

extent that the Commission applies asymmetric sharing of cost under- or overruns, this will 7

discourage IOU projects and potentially result in the loss of a valuable source of generation 8

resources. 9

2. Incentive Mechanisms, If Any, Should Be Reviewed on a Case-By-Case Basis 10

Although DRA opposes 50/50 sharing for utility generation project construction 11

costs, DRA suggests that cost overrun sharing mechanisms such as that approved in PG&E’s Contra 12

Costa 8 settlement would be appropriate as a means to avoid reasonableness reviews.76 TURN 13

suggests that the Commission address IOU construction cost and operating incentives on a case-by-14

case basis, tailored to the particular risks of concern for each given project. TURN further 15

recommends that IOUs be required to affirmatively address cost and performance incentives in 16

utility-generation project applications.77 SCE agrees that cost and performance incentives may be an 17

appropriate topic to be addressed by parties in IOU applications to construct new generation 18

projects. However, existing law already provides a “default” cost sharing arrangement, so TURN’s 19

recommendation to make this a requirement is unnecessary. Public Utilities Code Section 1003(c) 20

requires the utility applicant to submit “an appropriate cost estimate,” while Section 1005.5 imposes 21

a cost cap and specifies the conditions under which a utility may seek approval of the cap. 22

73 TURN/Florio, pp. 4-5, lines 20-15. 74 UCAN, p. 19. 75 Aglet/Reid and Weil, pp. 8-2 to 8-3, lines 13-10. 76 DRA, Vol. A, p. 40, lines 5-14. 77 TURN/Florio, pp. 19-20.

30

Thus, utilities are already subject to a construction cost cap, which specifies the 1

maximum amount that the Commission determines to be reasonable and prudent. A utility may seek 2

to increase the cost cap, but it is up to the discretion of the Commission to determine whether or not 3

to allow an increase in the cap. 4

3. Cost-of-Service Ratemaking Benefits Customers 5

WPTF urges the Commission to reject cost-of-service ratemaking for UOG, and 6

instead suggests that if IOUs are permitted to bid their own generation, then any IOU-owned 7

resources selected in a solicitation be required to submit firm bids for O&M, fuel costs, future plant 8

addition costs, environmental mitigation costs, and so forth.78 In contrast, Aglet supports traditional 9

cost-of-service ratemaking for IOU generation projects, with capital expenditures subject to a 10

combination of pre-approval and reasonableness review, O&M recovery adopted on forecast basis in 11

IOU general rate cases, and fuel-related expenses recovered through existing Energy Resource 12

Recovery Account (ERRA) mechanisms.79 13

Under cost-of-service ratemaking, IOUs commit their public utility assets to the 14

beneficial use of their customers (obligation to serve). Such assets may not be sold or encumbered 15

without Commission approval. In contrast, utility RFOs typically procure assets for shorter periods, 16

allowing the sellers to tailor their commitment period to reflect cost uncertainty. It is hard to 17

imagine a power plant owner being willing to offer fixed O&M expenses and fixed fuel expenses 18

over the expected economic life of a new generation project, at least not without an exorbitant 19

mark-up to the bid price. Thus, WPTF’s suggestion that utility “bids” be firm price fails to 20

recognize the nature of cost-of-service ratemaking. 21

WPTF complains that “cost overruns for utility power plants result in increased 22

earnings for utility shareholders.”80 Regulators have long recognized the need for balanced 23

ratemaking mechanisms that allow prudent and reasonable costs to be passed on to IOU customers, 24 78 WPTF/Ackerman, pp. 1-13, 1-14, 3-7, and 3-8. 79 Aglet/Reid and Weil, pp. 8-4 to 8-5. 80 WPTF/Ackerman, p. 3-6, lines 17-19.

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while not allowing unreasonable costs to be recovered. Thus, reasonableness reviews, cost sharing 1

mechanisms, and performance incentives are common ratemaking features that align the interest of 2

IOU shareholders and customers. Even forecast test year ratemaking has strong incentive attributes 3

– once a forecast is adopted, the IOU benefits from pursuing productivity incentives that allow it to 4

reduce the amount of O&M and capital that is required to provide service to its customers. Thus, 5

WPTF’s naïve assertion that IOUs benefit from cost overruns is plainly inaccurate. 6

4. FEED Study Costs Should Be Recoverable 7

DRA opposes SCE’s suggestion that it should be able to seek recovery of a front-end 8

engineering and design (FEED) study in advance of proposing a new plant. If the Commission were 9

to reject the concept of approving costs for such studies, then the risks associated with investigating 10

new generation options would be too great for the potential of regulated returns on such investments 11

if approved. The requests for such funds should be able to be considered, and approved or rejected 12

on their own merits. DRA would preclude this type of request from receiving consideration. SCE 13

believes that ratepayers would lose access to various future UOG options if the Commission were to 14

adopt DRA’s recommendation on this point. 15

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IV. 1

SCE’S REPOWERING PROPOSAL IS FAIR AND IT SUPPORTS THE OBJECTIVES OF 2

AB 1567 AND PRIOR COMMISSION DECISIONS 3

A. Overview 4

Certain parties appear to greatly misunderstand the intent of the Legislature and the 5

Commission regarding the inclusion of repowered facilities in a utility’s LTPP. Contrary to the 6

admonitions of Mirant and LS Power Generation (Repower Developers), prior Commission 7

decisions and AB 1576 do not require that repowered projects be given “head of line” privileges in 8

the planning and procurement processes. This major misconception underlies various repowering 9

proposals but it is not the only problem plaguing intervenors’ testimony on the repowering issue. 10

Other major erroneous proposals or suggestions were made. Contrary to these proposals: 11

• The CAISO’s annual Local Capacity Requirements (LCR) report is not a substitute 12

for the CAISO certification required by AB 1576 for Local Area Reliability;81 13

• Allowing project proponents to make direct proposals to the Commission outside the 14

utilities’ LTPP process is disorderly, inefficient and non-productive, and deviates 15

from the State’s primary objective in AB 57 of transferring the obligation to plan and 16

procure on behalf of bundled ratepayers back to the IOUs;82 17

• Transmission costs and losses are included in SCE’s bid evaluations; 18

• A cost-of-service arrangement requires greater certainty of the project’s 19

characteristics and requirements. All these elements are typically derived from the 20

project completing the Application For Construction (AFC) process at the CEC; 21

• Ten-year power purchase agreements are reasonable when compared to a “life-of the 22

asset” project when the costs of collateral and debt-equivalence are considered; and 23 81 Mirant/Bready and Driscoll, pp. 18-19, lines 24-1. 82 Mirant/Bready and Driscoll, pp. 20-21.

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• Contracting IOUs must have operational control of an AB 1576 repowered project to 1

ensure that it provides the local area reliability benefits associated with the CAISO 2

certification.83 3

The Commission should not adopt the Repower Developers’ proposals. Rather, the 4

Commission should implement the proposal and associated criteria for the implementation of 5

AB 1576 recommended by SCE in its LTPP.84 6

B. Repower Projects Do Not Have a “Clear Preference” in Resource Planning or 7

Procurement 8

Neither AB 1576 nor previous Commission decisions provide repower projects with “head of 9

line” privileges in an IOU’s planning or procurement processes. Although in two decisions85 the 10

Commission expressed its desire for IOUs to consider brownfield sites, it did so in a manner that 11

focused on the IOU’s development of new generation on the site, not as a policy that new generation 12

at existing sites be afforded an automatic preference in RFOs. As discussed below, in compliance 13

with the Commission’s desires, the relative advantages of reduced transmission losses and 14

investments from brownfield development is considered by SCE in its evaluation of proposals from 15

developers as part of its adopted procurement plan. 16

AB 1576 likewise focuses on the value of certain CAISO-certified sites and encourages their 17

repowering, but like the Commission decisions, it does so in the context of providing a cost-effective 18

project, which to protect ratepayers, should be contracted for on a cost-of-service basis. Moreover, 19

the statute neither requires that potential AB 1576 projects be pursued outside a utility’s normal 20

LTPP process, nor that repowered resources be given any special privileges if procured within the 21

normal process. 22

83 Mirant/Bready and Driscoll, p. 21. 84 R.06-02-013: SCE-1, Vol. 2, Section V of Southern California Edison’s December 11, 2006 submittal. 85 D.04-01-050 and D.04.-12-048

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C. CAISO Must Separately Certify That the Repower Project is Needed for Local Area 1

Reliability 2

Contrary to the suggestion of the Repower Developers, IOUs should not rely on the CAISO’s 3

annual Local Capacity Requirement (LCR) report for making their determinations that a particular 4

generating station is needed for Local Area Reliability. Such a finding must separately be made by 5

the CAISO, as the LCR report does not address the particular project need of a local area, but rather 6

encompasses a large number of generating resources covering a large physical area. 7

Moreover, as provided by AB 380, projects needed for local area reliability would be eligible 8

for cost recovery under Section 380(g) of the Public Utilities Code. As the Commission has 9

implemented this provision of law, the fixed costs associated with an AB 1576 repowered project 10

would be fully recoverable from all customers on whose behalf the costs are incurred. Given this 11

requirement in law, SCE believes that the CAISO must separately find that a particular repowered 12

project is needed to provide local area reliability service, rather than relying on the less-specific LCR 13

report. 14

D. Utilities Must Retain Responsibility For Implementing Their Own LTPPs 15

AB 1576 clearly indicates that its provisions apply only to contracts entered within an IOU’s 16

Commission-adopted procurement plan. The statute clearly precludes the Repower Developers’ 17

suggestion that project developers directly seek Commission approval of their projects, and even 18

more so their proposal that the project developers provide the Commission with the terms and 19

conditions of the anticipated contractual arrangement.86 An IOU operating under a Commission-20

adopted AB 57 procurement plan has the responsibility to conduct all solicitations and to enter 21

contracts “to provide the best value for ratepayers.”87 The Commission, of course, has the obligation 22

to ensure that the procurement was done in conformance with the adopted plan, or that procurement 23

outside the plan (and not otherwise preapproved) was reasonable. Transferring the obligation to plan 24

86 P.U. Code §454.5. 87 P.U. Code §454.6(a).

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and procure resources for bundled ratepayers from the DWR to the utilities, in a reliable and 1

efficient manner, was the State’s primary objective in adopting AB 57.88 It was never the intent of 2

the Legislature in adopting AB 57 or AB 1576 to allow project developers to circumvent an IOU’s 3

planning process. 4

E. Transmission Investment Costs and Transmission Losses are Considered by SCE 5

Mirant asserts in its supplemental testimony that the Commission must review and possibly 6

order a modification of the IOUs’ bid evaluation processes to ensure that the advantages associated 7

with a project located near a load center, both in terms of reduced infrastructure and operating costs, 8

are captured.89 Although SCE is not aware of what other IOUs consider in their evaluation 9

processes, SCE does consider the cost of transmission in ranking prospective bid submittals for all 10

generation procurement. To the extent additional transmission infrastructure and costs are required 11

to integrate and accept the power from a prospective project, those costs are included in the bid 12

evaluation. Likewise, if a prospective project involves an existing site, with all needed transmission 13

infrastructure already in place, few (if any) transmission costs would be included. To the extent the 14

site was close to a load center, the reduced transmission losses incurred in integrating the power 15

would give the bid additional value. 16

F. Additional Project Certainty is Needed for a Cost-of-Service Transaction 17

Since an AB 1576 transaction involves a local area reliability project, whose costs are 18

recovered under a cost-of-service paradigm, there must be added certainty as to what the 19

construction, operating and potential environmental mitigation requirements and costs will be at the 20

time of contract formation. SCE believes that for major generation projects, these are typically 21

identified as part of the CEC’s AFC process. Without that certainty, it would be much more difficult 22

to understand the various investment and operating costs that the project may incur in order to 23

comply with environmental law and policy. Recall that in order for SCE to obtain cost-of-service 24

88 P.U. Code §454.5. 89 Mirant Supplemental/Bready and Driscoll, p. 7.

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authority from the Commission for a thermal power plant of 50 MWs or more, it must have first 1

satisfactorily completed the CEC’s AFC process. Repowered facilities under an AB 1576 cost-of-2

service paradigm should be required to do the same. 3

G. Ten-Year Contract Versus the Life of the Asset 4

Finally, although TURN appears to generally support SCE’s proposal, TURN recommends 5

that the arrangement for a repowered facility be for the “life of the asset.”90 Although a “life of the 6

asset” approach provides customers with the likely “least-cost” alternative under a utility-build 7

regime, the collateral and debt-equivalence costs that are incurred by (and fairly applied to) a 8

purchased power arrangement makes it less attractive over the same period. Given the inclusion of 9

these costs, shorter duration arrangements may likely prove more cost-effective. 10

90 TURN/Florio, p. 25, lines 17-20.