STATE OF CALIFORNIA GRAY DAVIS, Governor

PUBLIC UTILITIES COMMISSION

505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

March 7, 2003 Agenda ID #1878

and

Agenda ID #1879

TO: PARTIES OF RECORD IN INVESTIGATION 00-11-001 AND
APPLICATION 01-04-012

Enclosed are the proposed decision of Administrative Law Judge (ALJ) Gottstein and alternate proposed decision of Commissioner Lynch. These items will not appear on the Commission's agenda for at least 30 days after the date they are mailed. This matter was categorized as ratesetting and is subject to Pub. Util. Code § 1701.3(c). Pursuant to Resolution ALJ-180 a Ratesetting Deliberative Meeting to consider this matter may be held upon the request of any Commissioner. If that occurs, the Commission will prepare and mail an agenda for the Ratesetting Deliberative Meeting 10 days before hand, and will advise the parties of this fact, and of the related ex parte communications prohibition period.

The Commission may act at the regular meeting, or it may postpone action until later. If action is postponed, the Commission will announce whether and when there will be a further prohibition on communications.

When the Commission acts on the proposed decision or the alternate, it may adopt all or part of it as written, amend or modify it, or set it aside and prepare its own decision. Only when the Commission acts does the decision become binding on the parties.

Parties to the proceeding may file comments on the proposed decision and the alternate as provided in Article 19 of the Commission's "Rules of Practice and Procedure." These rules are accessible on the Commission's website at http://www.cpuc.ca.gov. Pursuant to Rule 77.3 opening comments shall not exceed 15 pages.

Consistent with the service procedures in this proceeding, parties should send comments in electronic form to those appearances and the state service list that provided an electronic mail address to the Commission, including Administrative Law Judge (ALJ) Meg Gottstein at meg@cpuc.ca.gov. Service by U.S. mail is optional, except that hard copies should be served separately on ALJ Gottstein and the Assigned Commissioner, and for that purpose I suggest hand delivery, overnight mail, or other expeditious methods of service. In addition, if there is no electronic address available, the electronic mail is returned to the sender, or the recipient informs the sender of an inability to open the document, the sender shall immediately arrange for alternate service (regular U.S. mail shall be the default, unless another means-such as overnight delivery) is mutually agreed upon). The current service list for this proceeding is available on the Commission's web page, www.cpuc.ca.gov.

/s/ ANGELA K. MINKIN

Angela K. Minkin, Chief

Administrative Law Judge

ANG:tcg

ALJ/MEG/jgo/tcg DRAFT Agenda ID #1878

Ratesetting

Decision PROPOSED DECISION OF ALJ GOTTSTEIN (Mailed 3/7/03)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Order Instituting Investigation Into Implementation of Assembly Bill 970 Regarding the Identification of Electric Transmission and Distribution Constraints, Actions to Resolve Those Constraints, and Related Matters Affecting the Reliability of Electric Supply.	Investigation 00-11-001 (Filed November 2, 2000)
Conditional Application of PACIFIC GAS AND ELECTRIC COMPANY (U 39 E) for a Certificate of Public Convenience and Necessity Authorizing the Construction of the Los Banos-Gates 500 kV Transmission Project.	Application 01-04-012 (Filed April 13, 2001)

(See Attachment 1 for List of Appearances.)

TABLE OF CONTENTS

Title Page

INTERIM OPINION: ECONOMIC BENEFITS OF PATH 15 2

1. Introduction and Summary 2

2. Procedural Background 7

3. Issues and Scope 10

4. Project Description 11

5. Estimated Project Costs 12

6. ISO's Economic Analysis 13

6.1 ETCs and the Problem of Phantom Congestion 13

6.2 Path 15 Economic Assessment Assuming Competitive Market 16

6.3 Path 15 Economic Assessment Assuming Market Power 20

7. Position of the Parties 24

8. Discussion 26

9. Comments on Proposed Decision 40

10. Assignment of Proceeding 40

Findings of Fact 40

Conclusions of Law 43

INTERIM ORDER 43

LIST OF ATTACHMENTS

Attachment 1 - List of Appearances

Attachment 2 - List of Acronyms and Abbreviations

LIST OF TABLES AND FIGURES

Table 1 - ISO's Competitive Market Study

Table 2 - ISO Market Power Study

Table 3 - Summary Results of Estimated Cost Savings to NP15 Load from
Path 15 Expansion (Excluding Long-term Contracts)

Table 4 - Summary Results of Estimated Cost Savings to NP15 Load from
Path 15 Expansion (Including Long-term Contracts)

Figure 1 - Path 15

Figure 2 - Comparison of Average Simulated Price-cost Markups and Average Actual Price-cost Markups (2001)

Figure 3 - Comparison of the Simulated Price-cost Markups and Actual Price-cost Markups (November 1, 1998 to October 31, 1999)

INTERIM OPINION: ECONOMIC BENEFITS OF PATH 15

1. Introduction and Summary¹

Path 15 is the major transmission interface between northern and southern California. (See Figure 1.) During the latter part of 2000 and early 2001, congestion occurred on Path 15 on a regular basis. Although it was the middle of winter when demand was low, generation resources proved to be scarce. The California Independent System Operator (ISO) was forced to regularly call a stage three emergency, which is defined as the point where operating reserves are so low that rolling blackouts are imminent. California experienced two days of rotating outages of firm customer load and numerous days of threatened outages. On February 13, 2001, the Commission's Energy Division issued a report on transmission constraints in California and their impacts on system reliability and electric prices.² In that report, the Energy Division identified constraints on Path 15 between southern and northern California as a major factor affecting system reliability and resulting in unnecessarily high electric prices. In response to this report, on March 29, President Lynch issued an Assigned Commissioner's Ruling in the Transmission Investigation (I.) 00-11-01 that stated, in part:

"Over this past year, it has become increasingly clear that constraints on the transmission of power between northern and southern California have compromised electric reliability and the ability to dispatch lowest cost power. The Energy Division's report on transmission constraints identified constraints on [PG&E's] Path 15 that contributed most to `major reliability problems in the past year' and `likely to continue to cause problems in 2002'.... Further, that while new generation resources may have an impact on the cost-effectiveness of transmission system upgrades, the volatility of wholesale electricity markets suggests that relieving constraints on major transmission paths is an economic insurance policy (id., p. 12.)... Therefore, it is necessary for the Commission to pursue relieving the constraints on Path 15 now to ensure electric service reliability and lowest cost dispatch."³

By today's decision, we consider the economic benefits to ratepayers of adding 1500 megawatts (MW) of capacity to Path 15. More specifically, we examine the economics of the project on a "stand-alone" basis, i.e., without considering the manner in which Pacific Gas and Electric Company (PG&E) and other entities will participate in the project. In doing so, we have carefully evaluated the assumptions and methodology underlying the ISO's economic analysis in this proceeding. Based on our review, we conclude that the proposed upgrades are not cost-effective to ratepayers. Our conclusion is based on the assumption that Path 15 upgrades will cost $323 million (or approximately $50 million per year on an annualized basis).

As explained in today's decision, the ISO conducted two studies of the Path 15 upgrades in this proceeding. They differ substantially with respect to the estimated values of market clearing prices in 2005, particularly during hours of congestion over Path 15. In the first study, the ISO examined the economics of the upgrades assuming a competitive wholesale electric market in 2005 and beyond. Under this assumption, suppliers bidding in the market are unable to establish market prices above the marginal costs of production. During hours of congestion over Path 15, market clearing prices in northern California reflect the higher costs of less efficient resources that need to be dispatched from locations other than southern California. By reducing congestion in the south-north direction, the Path 15 upgrade reduces the market price for power flowing in that direction. However, the analysis indicates that these benefits are very small relative to project costs in all but two scenarios that assume one-in-ten year drought conditions and that low levels of new generation are built in northern California and in the Pacific Northwest.

In the second study, the ISO assumed that the market power abuses experienced in 2000 would continue unabated in 2005 and beyond, resulting in market prices that reflect very large price-cost mark-ups, particularly during the hours of congestion over Path 15. As a result, the ISO's estimate of the economic value of reducing congestion over Path 15 in the second study is dramatically higher than in the first. Based on the results of this study, the ISO concludes that the project would pay for itself in one drought year and three normal years.

As discussed in this decision, we find that the ISO's second study is seriously flawed, for several reasons. First, the ISO fundamentally errs in its market power assessment by putting arguably the most expensive fix-construction of a $323 million transmission project-as the first step in mitigating the market abuses experienced in 2000. This sequence results in inflated project benefits because those benefits are measured when market power is at its maximum. It presumes that regulators will fail to take any other action to address market power abuses or transmission congestion in the future and ignores the initiatives that have been put in place by this Commission and other agencies since 2000 to address these issues, such as forward contracting, demand-responsiveness programs, and incentives for distributed generation.

Second, the ISO's approach to estimating the impact of market power on prices omits an important modeling parameter that further biases the results of its market power study in favor of project construction. The omission affects the ISO's calculation of market concentration in 2005, which is then used as a predictor of market prices in 2005 in a regression analysis. The upward bias in the model is further substantiated by a comparison of estimated and actual price-cost markups in 2001 prepared at the direction of assigned Administrative Law Judge (ALJ). (See Figures 2 and 3.) As discussed in this decision, the predictive weakness of the model is also consistent with our observation that the ISO's regression analysis does not meet standards of statistical validation in six months out of the year.

Third, of the 24 scenarios conducted under the market power study, we find that 18 scenarios are simply implausible. Twelve of them assume that all load will be met in 2005 and beyond through spot market transactions exposed to price-cost markups, i.e., none of the Department of Water Resources (DWR) long-term contracts will continue (or be replaced by DWR or utility bilateral contracts) in 2005 and beyond. Six others assume that "phantom congestion" will continue to impede the efficient use of existing Path 15 capacity in 2005 and beyond in the same manner that it did in 2000.

After eliminating these implausible scenarios, the ISO's analysis produces three scenarios where annual project benefits exceed project costs. However, these scenarios assume one-in-ten year drought year conditions or relatively pessimistic forecasts concerning new generation development north of Path 15, or both. Overall, the negative net benefits accumulated in the average hydro years are far greater than the positive net benefits accumulated in the drought years. Put another way, for every five years of average hydro conditions, you would need eight years of drought conditions for the project to break even.

We do not consider these to be likely conditions in 2005 and beyond. Moreover, as discussed above, these results were produced by a modeling effort that, in our view, lacks convincing validation and contains the upward biases described in this decision. Based on the record, we conclude that the ISO's market power study does not produce reliable or reasonable estimates of economic benefits with which to assess the Path 15 upgrades. Even if we could rely on the estimates produced by this study, the results indicate that the costs of the project would not even catch up with estimated benefits within a ten-year period, except under implausible scenarios.

As discussed in this decision, we believe that the ISO's analysis of Path 15 economic benefits should have acknowledged that various market power mitigation strategies are currently in place and/or will be in place between now and 2005, and then measured the effect of Path 15 upgrades on mitigating any residual market power costs. The closest approximation in the record to what the results of such an approach would likely be is the ISO's study that assumes the wholesale market will be competitive by 2005.

Under this study, the annual benefits of the upgrade are less than costs in all of the scenarios where either (1) average hydro year conditions or (2) medium or high new generation north of Path 15 are assumed. In scenarios that assume average hydro conditions, the project costs exceed benefits by $47 million/year or more, regardless of the level of new generation assumed. In fact, under four out of the ten scenarios, the Path 15 upgrade actually increases market prices overall, i.e., the benefits of the project are negative by approximately $2.5 to $7.5 million. This is because the addition of 1500 MW in Path 15 transfer capacity increases market prices south of Path 15 more than it decreases market prices north of Path 15.

The two scenarios where annual benefits are greater than costs assume one-in-ten year drought conditions and relatively low levels of new generation north of Path 15. Even if we believed that the low new generation scenario is likely, the project would not be a cost effective investment to ratepayers unless there are a greater number of years with drought conditions in the future than there are years with average hydro conditions.

Based on record in this proceeding, including the project costs presented by PG&E in its testimony, we find that the proposed upgrades to Path 15 are not cost-effective to ratepayers. In a further phase of this proceeding, PG&E will submit updated project cost estimates and agreements among participants regarding the allocation of project costs and benefits. Those participants are: PG&E, Western Area Power Administration (WAPA) and Trans-Elect, Inc. (Trans-Elect). We may revisit today's findings if that information changes the project economics significantly.