B. The Parties' Testimony

In keeping with the schedule set forth in the Scoping Memo, the utilities served their updated testimony on March 4 and the intervenors served their direct testimony on March 11, 2005.

In its March 4 update, PG&E used the most up-to-date data on marginal costs and NBCs. The effect of these changes was to reduce the expected CTM from 10% to 6% in the first year. (Exhibit 1, p. 2-5.) In addition, although the proposed rate that converting customers would pay remained the same ($0.07539/kWh), the resulting revenue allocation changed. PG&E also simplified and consolidated the forms it was proposing to use.

On the issues of system reliability and how much additional load the conversion program might produce, PG&E began by noting that due to the construction lead times for line extensions, it did "not expect a significant amount of new load to occur during summer 2005." (Exhibit 1, p. 5-1.) For 2006 and 2007, PG&E assumed an additional 325 Mw of new coincident peak load, the high estimate in the range AECA had calculated assuming all of the agricultural diesel pumps in PG&E's service area converted to electricity. Even with this much new load, PG&E asserted, the California Energy Commission's most recent assessment showed that under an extreme planning scenario, PG&E would still have an excess of 330 Mw in 2006 and 95 Mw in 2007, and these figures did not take into account a new contract PG&E had entered into with Duke Energy for 650 Mw of additional capacity. (Id. at 5-2.) Thus, PG&E concluded, there was ample electric supply available to serve the incremental electric load that the conversion program could be expected to produce. (Id. at 5-1.)

In its updated testimony, Edison also concluded that the likely new load did not pose any reliability concerns. Since eight weeks would be required for a customer to begin receiving power once it signed up for the conversion program, and since a Commission decision approving the program was not expected before June 30, 2005, Edison anticipated no load impacts in 2005. It also projected that a total of only about 100 customers were likely to sign up for the program by 2007, who would add about 3.4 Mw in coincident peak load. Two-thirds of this likely incremental load was located in Kern and Tulare Counties, which are served by a number of transmission circuits located north of congested Path 26. (Ex. 3, pp. 2-3.)

Significantly, Edison's March 4 update reduced its proposed average rate discount from 20% to 12.5%, a change that meant customers converting their pumps from diesel to electricity in both the PG&E and Edison service territories would be paying an initial rate of $0.07539 per kWh. With this change, Edison noted, its price floor -- including all marginal costs and NBCs -- would provide a 5.5% CTM in the first year.⁸ (Id. at 4.) When combined with the proposed 1.5% annual increase in the rate, Edison asserted this would "help[] insure recovery of positive CTM over the term of the agreements." (Id. at 5.)

In the testimony it served on March 11, TURN took sharp issue with the utilities' proposal to offer converting agricultural customers a flat adder ($32,395 in PG&E's case, $29,942 in Edison's) in addition to the line extension allowances for which the customer would be eligible. According to TURN:

"Applying a fixed line extension adder to extensions intended to convert irrigation pumps that range from 50 hp to 500 hp, will result in ratepayers paying a wide range of costs for NO_X emission reductions on a dollars per kW basis. Under Edison's proposal ratepayers would pay from $60/kW to $600/kW for NO_X reduction, while under PG&E's proposal ratepayers would pay between about $65/kW and $650/kW for NO_X reductions.

"Instead of providing an `adder' that results in such a wide range of costs for NO_X reductions, TURN suggests providing a line extension adder closer to the average costs for NO_X emission reductions estimated by the utilities. Both PG&E and Edison calculate their line extension adder based on converting an average sized engine of 150 kW. For Edison this results in an average ratepayer investment for NO_X emission reductions of $200/kW.

"TURN believes it is more reasonable for ratepayers to invest this `average' for NO_X emissions reductions than the extremely wide range of costs that would result from a single fixed line extension adder . . . In order to prevent ratepayers from providing large subsidies for agricultural customers who are at extreme ends, . . . the line extension adder should be capped at the lower of either $200/kW or $40,000 for any individual customer." (Ex. 5, pp. 3-4.)

In addition to capping the proposed adder, TURN suggested that a cap should be imposed on the utilities' total spending for line extensions arising out of the conversion program. Noting that PG&E had estimated it would spend somewhere between $34 and $127 million on the new program, while its current spending on line extensions for agricultural customers was not more than $1.5 million, TURN said "it is not at all reasonable or prudent to increase capital spending at a level well over two magnitudes . . . greater than normal." To mitigate the potential for such "gargantuan" increases in spending, TURN recommended a cap for the conversion program of $20 million for each utility. (Id. at 5.)

In addition to its concerns about the proposed adder, TURN also suggested that the Commission should adopt one of three measures to ensure that the engine conversion program did not add so much additional load as to endanger system reliability. TURN recommended that the Commission should either (1) require that all new pumps installed under the program be equipped with direct load control devices controlled by the utility, or (2) require that customers signing up for the program agree to be interruptible customers, or (3) require that the conversion program retain the current on-peak charges set forth in the otherwise applicable tariffs. (Id. at 7-10.) In order to discourage the utilities from using the conversion program to gain a competitive advantage over municipal utilities and irrigation districts competing for the same agricultural load, TURN also proposed that if a territory serving a diesel conversion customer was taken over by a municipal utility or irrigation district in the program's first eight years, the utility's shareholders should be required to pay half of the rate discounts received by the conversion customers back to ratepayers. (Id. at 10-11.) TURN also argued that the Commission should declare that all emission reductions arising from the program and not donated to CARB or the applicable air quality district should be considered ratepayer property. (Id. at 11.)

While ORA recommended that utility shareholders should pay for 25% of the rate and line extensions (since shareholders would benefit from the likely load growth), and that PG&E should reduce its rate discount to 12.5% (as Edison had done), most of ORA's testimony was devoted to the CTM issue. Arguing that the best measure of the proposed conversion was its impacts on non-participating customers (i.e., all customers not signing up for the conversion program), ORA concluded that for PG&E, the first-year CTM was near the breakeven point when using the NCO method, while the CTM over the 10-year life of the program was negative. The results were better for Edison because it was proposing only a 12.5% rate discount, and also used less up-to-date marginal costs. (Ex. 4, p. 2-6 to 2-7.)

ORA also argued that the NCO method of computing CTM understated the conversion program's true costs, and that the so-called rental method was preferable. ORA explained the difference between the two methods and their impacts as follows:

"The NCO method was developed specifically for use in revenue allocation, and the Commission's approval of this method for that application does not make it appropriate for all applications. The method was designed to address the specific problem of how to reflect hookup cost in a revenue allocation purportedly based on marginal costs when this cost is sunk and not marginal for any existing customer. In the interest of not excluding this cost entirely, the Commission opted for including only a small fraction of the hookup cost. The opposing method . . . is the so-called `rental' method. It is based on a market principle where the `rent' associated with the entire cost of a new hookup is charged to each and every customer, even to those whose hookups were installed many years ago. The two methods produce very different results for PG&E because the number of new customers constitute only 0.16% of the pool of customers in any given year. The two methods yield very similar results for [Edison] owing to its much larger agricultural customer growth rate.

"Though the rental method has been rejected for use in revenue allocation, it is well suited for an analysis where all the customers are all new, such as in the [agricultural engine conversion] program." (Id. at 2-8 to 2-9; footnotes omitted; emphasis in original.)

After describing and emphasizing the uncertainties in the data used by PG&E and Edison, ORA recommended that the conversion program could be improved by limiting the ratepayers' exposure for line extension costs. Specifically, for pump sizes under 400 kW, ORA recommended that the line extension allowances (including the adder) be limited to what would be paid for a line extension of 1,000 feet. Such a limitation, ORA argued, would eliminate double digit negative CTMs, and affect only 5% of potential program participants (according to AECA's analysis). Thus, it seemed the best solution to the problems that ORA's analysis had identified. (Id. at 2-11 to 2-13.)

The California Farm Bureau Federation (CFBF) also submitted testimony on March 11. Most of CFBF's testimony was devoted to the system reliability and CTM issues. On system reliability, CFBF echoed the view of other parties that little, if any, additional load was likely to result from the engine conversion program during summer 2005. With respect to future years, CFBF noted that while most of the engine conversions were likely to take place in PG&E's territory, discussions with CFBF members indicated that the program's participation rate was not likely to reach even 50% of the eligible engines. In view of this, CFBF calculated that the maximum amount of additional peak load likely to be added to PG&E's system was about 153 Mw, and for Edison, somewhere between 4 and 41 Mw. Thus, CFBF agreed that the conversion program was not likely to pose any reliability concerns during the 2005-2007 period. (Ex. 6, pp. 2-3.)

On the CTM issue, CFBF agreed with the utilities that their most recent marginal cost proposals should be used in the calculations, because owing to electric restructuring, it had been many years since the Commission had adopted any marginal costs. On the question of whether NBCs should be included when computing the price floors used to determine CTM, CFBF argued that it was proper to include NBCs only to the extent they were marginal, and would increase with additional load. In CFBF's view, most of the NBCs were historic, sunk costs, and so did not meet this test for inclusion. Overall, CFBF concluded, the conversion program would result in a positive CTM.

CFBF also argued that because of the need for a "high level of [rate] predictability" to induce agricultural customers to participate in the conversion program, critical peak pricing should not be incorporated into the engine conversion rate, even if such pricing were to be adopted for other customers in future years. CFBF also asserted that the Commission should not complicate the rate (and the related customer investment decisions) by requiring the use of devices such as variable speed motors. (Id. at 5-7.)

Dr. McCann also submitted revised testimony on behalf of AECA on February 24, 2004. Dr. McCann's February 24 update retained and corrected the text and tables in his January 21 testimony, and - to account for the uncertainty as to how many eligible agricultural customers might sign up for the conversion program -- added a series of sensitivity analyses purporting to show, under the Ratepayer Impact and Total Resource Cost tests, what a base case and break even cases would be for evaluating when the costs of the program would begin to shift to ratepayers. (Ex. 7, pp. 12-14.)⁹

"These sensitivity analyses are not intended to reflect what may actually happen, but rather are intended to determine what conditions are required to cause the program to become a money loser. In other words, it is a risk analysis, not a revenue or rate forecast. The `base case' just shows some assumed results which may be in the ballpark of where things could come out if all of the engines were converted - it is not a revenue forecast. The answer to the sensitivity analyses is that either the engines have to be really small . . . or the lines have to be exceptionally long compared to historic agricultural installations, particularly in the case of [Edison]. While PG&E shows the greatest risk on the RIM test, it also shows the largest potential societal benefits." (Ex. 7, pp. 14-15.)