ALJ/MCK/tcg DRAFT Agenda ID #4648

Ratesetting

6/16/05 Item 21

Decision PROPOSED DECISION OF ALJ MCKENZIE (Mailed 5/25/2005)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Pacific Gas and Electric Company (U 39 E) for Rate and Line Extension Incentives for Conversion of Stationary Agricultural Internal Combustion Equipment to Electric Service.	Application 04-11-007 (Filed November 9, 2004)
Application of Southern California Edison Company (U 338-E) for Rate and Line Extension Incentives for Conversion of Stationary Agricultural Internal Combustion Equipment to Electric Service.	Application 04-11-008 (Filed November 9, 2004)

OPINION APPROVING ALL-PARTY SETTLEMENT AGREEMENT

TABLE OF CONTENTS

Title Page

OPINION APPROVING ALL-PARTY SETTLEMENT AGREEMENT 1

A. Procedural Background 3

1. The Applications 3

2. The Protests of ORA and TURN 5

3. The Two Prehearing Conferences and the Technical Workshop 7

B. The Parties' Testimony 13

C. The March 30, 2005 Joint Settlement 20

D. Discussion 25

E. Findings of Eligibility for Intervenor Compensation 33

F. Assignment of Proceeding 37

G. Comments on Proposed Decision 37

Findings of Fact 37

Conclusions of Law 38

ORDER 41

Attachment A

OPINION APPROVING ALL-PARTY SETTLEMENT AGREEMENT

In this decision, we approve a settlement signed by all of the active parties in these proceedings, in which Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) seek authority to offer reduced rates and additional line extension allowances to agricultural customers who convert engines used for agricultural pumping from diesel fuel to electricity. Under the settlement, converting customers in PG&E's service area would receive a 20% reduction (and customers in Edison's service area a 12.5% reduction) from the otherwise applicable tariff for their engine use. The rate reductions would remain in effect for ten years, subject to escalation of the total average rate at 1.5% per year.  Ratcheted demand charges would be eliminated from the rates for the new engines, and customers would not be subject to any deficiency charges. Customers electing to take advantage of this program would also receive one of three additional line extension allowances (referred to as "adders") depending on the size of the new electric engine, in addition to the standard extension allowances authorized by the respective PG&E and Edison tariffs. In consideration of the rate reductions and additional line extension allowances, converting customers would be required to destroy their old diesel engines and assign the resulting air emission reductions to the utilities. With the exception of carbon dioxide (CO₂) reductions, the emission reductions would then be transferred by the utilities to the California Air Resources Board (CARB) or the customer's local air pollution district.

Even if it achieves a relatively modest level of participation, the engine conversion program set forth in the settlement should result in a significant improvement in the air quality of the Sacramento and San Joaquin Valleys, which have some of the worst air quality in the nation. The engine conversion program would remain open for two years, or until the capital expenditures associated with the line extensions (both standard allowances and adders) reached $27.5 million for PG&E and $9.17 million for Edison.

Because the engine conversion program in the settlement agreement is likely to result in meaningful air quality improvements, and because the concerns about the utilities' original proposals appear to be effectively addressed by (1) the $36.67 million capital cost limitation described above, and (2) the tying of the line extension adders to the size of the electric engine installed, we conclude -- in accordance with Rule 51.1(e) of our Rules of Practice and Procedure -- that the settlement is reasonable in light of the whole record, consistent with law and in the public interest. We will therefore approve it.

A. Procedural Background

1. The Applications

PG&E and Edison filed their applications on November 9, 2004. The applications were nearly identical, except that the average discounted electric rate a PG&E customer signing up for the engine conversion program would pay was $0.07539 per kilowatt-hour (kWh), while the average rate an Edison customer would pay was $0.06893 per kWh. PG&E proposed to offer a flat line extension adder of $32,935 to each customer signing up for the program, regardless of engine size, while Edison proposed to offer each customer signing up for its program a flat adder of $29, 942. These adders were based on the value of emissions of oxides of nitrogen (NO_X) used by CARB. PG&E and Edison also proposed that converting customers should be required to assign the emission reductions obtained as a result of the conversion program to the utilities, which in turn would transfer them (with the exception of CO₂ reductions) to CARB or the applicable air pollution control district. PG&E and Edison both requested an exemption from Pub. Util. Code § 851 in connection with these transfers.

Each application also asserted that the proposed incentive rate would make a positive contribution to margin (CTM), and that because this was the case, the Commission should not reexamine either the CTM issue or the related issue of agricultural customers' marginal costs during the 10 years the discounted incentive rate would be in effect.

The principal benefit of the engine conversion program, the utilities argued, was that it would result in much cleaner air in the Sacramento and San Joaquin Valleys. The utilities cited data from CARB that diesel engines used for agricultural pumping presently account for approximately 23% of the NO_X emissions from stationary fuel combustion sources in the central valleys, and about 31% of the emissions of reactive organic gases (ROGs). The utilities also urged the Commission to act promptly on the applications, so that agricultural customers could take advantage of funds in the Carl Moyer Memorial Air Quality Standards Program¹ to help fund the conversions from diesel to electric engines.

On November 16, the utilities filed a joint motion to consolidate the two proceedings. On November 24, 2004, the Agricultural Energy Consumers Association (AECA) filed petitions to intervene in both proceedings, which were accompanied by a motion for expedited consideration and decision.

2. The Protests of ORA and TURN

In mid-December 2004, both the Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) filed protests to the applications. In its protests,² ORA stated that it would propose a schedule after the first prehearing conference (PHC), and intended to conduct discovery and submit testimony on the following issues:

1. Whether the proposed rate reductions for customers installing new engines would really amount to 20%, and whether the proposed line extension adders were reasonable when compared with recent line extensions for other customers located in the same geographic areas.

2. Whether the additional electric load that would be created by converting diesel pumps to electric pumps would result in an imprudent increase in demand for electricity, "especially during a time of predicted shortage of both generation and transmission capacity."

3. Whether PG&E and Edison had considered the installation of "zero pollution" energy devices such as wind turbines and photovoltaic cells to handle the increased electric load that could be expected as a result of the engine conversion program.

In the joint protest of both applications that it filed on December 16, 2004, TURN raised similar issues, but with a somewhat different focus. First, TURN noted, significant capital costs would have to be incurred to connect the widely-dispersed agricultural pumping customers to the PG&E and Edison systems. These costs would be included in the rate base in the utilities' future general rate cases (GRCs), potentially resulting in a significantly increased revenue requirement that non-agricultural customers would have to bear. In addition, TURN noted, since pumping engines are used by agricultural customers only when there is a water shortage, it was possible that the new electric engines would be used much less often than was assumed in the utilities' calculations for the line extension adder. The effect of such a miscalculation would be to increase the revenue shortfall that eliminating deficiency billings - another aspect of both the PG&E and Edison proposals - seemed likely to bring about. (TURN Protest, pp. 2, 4.)

TURN also raised concerns about the effects of the engine conversion program on electric reliability. TURN noted that the conversion of diesel engines to electric service could increase load by as much as 400 megawatts (Mw), a serious concern in view of statements by some officials that "reserves may fall below 0% during 1-in-10 conditions in southern California during the summer of 2005." (Id. at 6.) At the same time, TURN pointed out, PG&E was proposing in Rulemaking (R.) 02-06-001 that customers in the Bay Area Air Quality Management District should be offered incentives to retrofit their existing diesel back-up generators, so that these generators could be run on days with high electric demand. (Id. at 6-7.)

Finally, TURN noted, the utilities did not furnish enough information about the incremental air quality benefits of their proposals to enable parties to determine whether the proposed adders and 20% rate reduction were reasonable. TURN also argued the Commission should consider whether additional conditions (such as reducing only off-peak agricultural rates) should be required before the engine conversion program was approved. Since discovery would be needed on these and the other issues TURN had raised, TURN urged that a PHC be held in January 2005, at which time the Commission should set a reasonable yet expeditious hearing schedule.

On December 23 and 27, respectively, PG&E and Edison filed brief replies to the protests, in which they suggested that technical workshops might be useful to work through some of the issues raised by the protests.

3. The Two Prehearing Conferences and the Technical Workshop

The first PHC in these proceedings was held on January 14, 2005. At this PHC, the assigned Administrative Law Judge (ALJ) provisionally granted the motion to consolidate the two applications, and then discussed with the parties how the many issues raised by the protests should be handled. After a short time, there was general agreement that, as PG&E and Edison had suggested, a workshop would be helpful.

The first of the issues raised by the ALJ was the amount of additional electric load that might result from the conversion program in 2005. After noting TURN's estimate that the conversion program could ultimately result in an additional 400 Mw of load in the combined geographic area served by Edison and PG&E (an estimate the utilities said they did not necessarily accept), the ALJ noted that additional load of such magnitude was a real concern, especially in view of the tight reserve margins expected in Southern California in the summer of 2005. The ALJ therefore asked the applicants and AECA how they intended to address it. AECA's counsel pointed out that owing to the leadtimes involved in constructing line extensions, ordering new engines, etc., the amount of additional load that could be expected in summer 2005 was small. (January 14 PHC Transcript, p. 32-34.) AECA counsel also noted that to the extent additional load in summer 2005 remained a concern, it could be addressed by capping the amount of new pumping load that would be permitted then, or -- as Edison had suggested -- by limiting the 20% discount rate to the off-peak period. (Id. at 33, 53.)

The second issue raised by the ALJ was the status of the marginal cost data on which PG&E and Edison had based their assertions that the proposed rate would result in a positive CTM.³ Discussion revealed that while Edison's marginal cost proposals were the subject of a pending settlement supported by most parties in A.02-05-004 (Phase 2 of Edison's 2003 GRC),⁴ there was no imminent prospect of resolution with respect to PG&E's marginal cost proposals. The marginal cost data on which PG&E had based its engine conversion rate was an issue in A.04-06-024, the rate design proceeding that arose out of Phase 1 of PG&E's 2003 GRC, but a decision in A.04-06-024 was not expected before the end of 2005, and the parties did not appear close to a settlement. (January 14 Tr., pp. 75-76.) The ALJ stated that he thought the parties' differences over marginal costs and CTM were another appropriate subject for workshop discussion.

A third issue considered at the PHC was whether a ruling on the applications was, in fact, an urgent priority. AECA argued that an immediate decision was vital because investment decisions had to be made soon about the most cost-effective way of complying with the new air quality regulations for the Sacramento and San Joaquin Valleys required by SB 700.⁵ TURN, on the other hand, argued that the continued availability of Carl Moyer Program funds ensured by AB 923⁶ meant, as a practical matter, that the applications did not need to be processed on the highly expedited schedule sought by AECA and the utilities. Because the competing arguments seemed to depend on statutory requirements, the ALJ directed TURN to file a short brief by January 20, 2005 setting forth its interpretation of the applicable statutes, with AECA filing a reply brief on January 24.

To assist the parties in their workshop deliberations, AECA agreed to serve its testimony in advance of the workshop. On January 21, 2005, Richard McCann, Ph.D., submitted testimony on behalf of AECA. In his testimony, Dr. McCann reiterated many of the utilities' arguments in favor of the engine conversion program, but also included a series of tables purporting to show (1) where the 5700 diesel pumps located in the San Joaquin and Sacramento Valleys were distributed, (2) the necessary "breakeven" point in electric rates that would induce agricultural customers to convert their diesel irrigation pumps to electric service, assuming a variety of crops and well-depths, and (3) how the net revenues that could be expected from electric pumping engines would exceed the costs of the line extensions, even with the adders.

The technical workshop was held on January 28, 2005. The principal topics discussed were the issues identified by the ALJ, as well as related questions such as whether any of the air emission reductions obtained as a result of the engine conversion program should be sold to help reduce the future costs that ratepayers would have to bear. A follow-up session was held on February 1, 2005, during which the parties discussed questions related to the CTM issue, including (1) whether the marginal costs on which the CTM calculations were based should be required to include non-bypassable charges (NBCs), (2) whether the valuation of air quality benefits that formed the basis for the proposed line extension adder was reasonable, and (3) whether the adder was reasonable when compared with the line extension allowances available under the current agricultural rate schedules.

Pursuant to an agreement reached on January 14, a second PHC was held on February 4, 2005. The ALJ opened the second PHC by pointing out that since no stipulations had apparently resulted from the workshop, it would be necessary to set a hearing schedule. (PHC Tr. At 83.)

Counsel for AECA argued that based on his understanding of the workshop discussions, hearings were not necessary and briefing should be sufficient. In particular, he argued that the protestants should not be allowed to litigate the question of whether marginal cost calculations should be based on the New Customer Only (NCO) methodology or the rental methodology, because the Commission had consistently favored use of the NCO methodology in its decisions. (Id. at 85-89.) ORA argued, however, that these other decisions had dealt with revenue allocation issues, and that the utilities' proposals here presented a different question - i.e., quantifying the cost of the conversion proposal -- for which the rental methodology was particularly appropriate. (Id. at 90-92.) After further discussion, the ALJ ruled that the NCO-versus-rental methodology issue could not be resolved on the record before him, and that the parties would be expected to address it in their testimony. (Id. at 92, 106.) The ALJ also rejected AECA's argument that ORA and TURN had had enough time for discovery, and should be required to specify immediately their factual differences with AECA and the utilities. (Id. at 92-94.)

Before proposing a schedule of his own, the ALJ asked ORA to present the schedule it had promised at the first PHC. ORA's proposal gave the intervenors six weeks to prepare their testimony and provided for hearings in early May, with final briefs to be submitted in early June. (Id. at 99-100.) However, the ALJ stated that in view of the considerations raised in AECA's January 24 response to TURN's brief on legal deadlines, such a schedule was too leisurely, and that the objective should be to issue a decision at the Commission's June 30, 2005 meeting. To this end, the ALJ proposed a schedule calling for the submission of intervenor testimony on March 4, hearings in early April, and the mailing of a draft decision on May 31. (Id. at 112.)

After some off-the-record discussion without the ALJ, the parties agreed that (1) the ALJ's proposed schedule should be modified slightly to allow an additional week for the preparation of intervenor testimony, (2) the time for comments on the proposed decision should be shortened by a week, and (3) PG&E and Edison should file updated testimony concerning their proposals on March 4. These adjustments were accepted in the procedural schedule set forth in the Scoping Memo issued by Assigned Commissioner Brown and ALJ McKenzie on March 3, 2005.⁷

"The Carl Moyer Memorial Air Quality Standards Program . . . is a grant program that provides funds for the purchase of cleaner-than-required engines and equipment, including agricultural pumps, in order to reduce air emissions [and ensure compliance with state and local implementation plans so as to avoid the loss of federal highway funds.] "In essence, the Carl Moyer Program provides taxpayer funding to reduce emissions from various sources, provided the associated emission reductions:

· Are not required by regulation; · Meet a prescribed cost effectiveness based on a dollar per ton of reductions value; and · Belong to the state or the air district providing the funding (that is, the reductions are not for sale as emission offsets)." (Exhibit 1, pp. 1-3 to 1-4.)

"The utilities have used the same approach that has been adopted in the past to approve Economic Development Rates (EDR) and Uneconomic Bypass rates; that is, to compare the marginal cost . . . for service to those customers to the expected revenue from the rates. Where the expected revenue is above the marginal cost . . ., the difference between the two is the estimated CTM." (Ex. 6, p. 4.)

"In response to the air quality problems in the central valleys, the California Legislature passed Senate Bill (SB) 700 [in 2003], . . . which amended the air pollution control requirements in the California Health and Safety Code for agriculture. SB 700 eliminated the agricultural operation permit exemption in its entirety and requires air districts to adopt best management practices to reduce or eliminate air pollution from agricultural operations. Hence, air districts are currently considering a number of new emission control requirements that are likely to go into effect in the near future. These new environmental requirements - which are not yet finalized and will vary by air district - will eventually require diesel engines in San Joaquin Valley, the South Coast, Sacramento County, the Mojave Desert, and Imperial County to implement `Best Available Retrofit Control Technology'; that is, these regulations are expected to require the installation of emission-control equipment, replacement with cleaner engines, or some other reduction technology." (Exhibit 1, p. 1-3.)

"These amendments to the Carl Moyer Program essentially mean that agricultural customers will still be able to apply for funds to retrofit or replace their non-certified diesel engines with certified diesel or electric engines even after the new regulations go into effect on January 1, 2006. Those customers affected by Rule 4702 [the San Joaquin Valley Unified Air Pollution Control Districts's proposed regulation to comply with SB 700], for example, will be eligible for funds until January 1, 2009 or until the date they are required to comply with new emission limits. As mentioned above, the earliest compliance date for existing non-certified diesel engines is July 2007." (TURN Brief, p. 5.)