D. Discussion

We have decided to approve the April 30 Joint Settlement because of the reasonable balance it strikes between the competing interests in this case. On the one hand, residents of the Sacramento and San Joaquin Valleys seem likely to benefit from substantial improvements in their local air quality, while participating agricultural customers will receive a rate that is guaranteed for 10 years (apart from the 1.5% annual escalation factor), as well as an adder that supplements the line extension allowances to which they would otherwise be entitled.  At the same time, ratepayers will be protected from excessive costs because (1) total capital investment in line extensions and adders for the engine conversion program will be capped at $27.5 million for PG&E and $9.16 million for Edison, (2) the graduated nature of the adders will help to ensure that ratepayers are not paying excessive amounts for the NO_X reductions that will result, and (3) any CO₂ emission reductions resulting from the conversion program will remain ratepayer property. We are also satisfied that the additional load likely to come about in the next few years from the engine conversion program does not pose any reliability concerns.

There is no dispute that the population of diesel-powered engines contributes significantly to the poor air quality in California's Central Valley. PG&E's updated testimony describes the current situation as follows:

"The San Joaquin and Sacramento Valleys are subjected to heavy amounts of air pollutants, ranking with the Los Angeles basin as one of the most polluted regions in the nation.  Air pollution in the California central valley persistently exceeds the national ambient air quality standards.  According to [CARB,] agricultural sources contribute 26 percent of the smog forming emissions in the San Joaquin Valley. CARB estimates that there are more than 5,700 stationary diesel-powered pumps used for irrigation in the central valleys, which are significant contributors to agriculture's air quality impact.  In part because of agriculture's air quality impact, the Sacramento and San Joaquin Valleys are currently classified as Federal Air Quality Non-Attainment areas for ozone, which could result in a reduction of federal transportation funding for California.

"During the 2003 summer, CARB estimates that diesel irrigation in the central valleys emit 33 tons per day of oxides of nitrogen (NO_X), which accounts for nearly 23 percent of the total NO_X emissions from stationary fuel combustion sources in the region.  In addition, CARB estimates that diesel pumps represent about 31 percent of the reactive organic gases (ROG) from stationary fuel combustion sources in the central California valleys.

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"The region suffers from unhealthy air quality in the winter months as well, largely due to particulate matter (PM) emissions.  CARB estimates that during 2003, 17 percent of PM emissions from stationary fuel combustion sources in the region were caused by diesel-powered irrigation pumps. It is estimated that PM accounts for 70 percent of the known cancer risk that is attributable to exposure to toxic air pollutants in California."  (Ex. 1, pp. 1-1 to 1-3; footnotes omitted.)

It is because of these problems, and especially because of the low-level ozone created during the summer by the reaction of sunlight, NO_X and ROGs, that CARB and two regional air quality control districts have expressed their support for the Joint Settlement.¹² Although the settling parties disagree as to the number of diesel engines likely to be taken out of service as a result of the conversion program, it seems clear that even if the program achieves a relatively modest level of participation, significant improvement in the Central Valley's air quality should result.  It was largely for this reason that ORA decided to support the settlement, even though it concluded that CTMs over the ten-year life of the incentive conversion rate are likely to be negative.¹³

Based on the testimony of the utilities and CFBF, we are also satisfied that any additional peak load resulting from the conversion program is not likely to pose reliability problems during the 2005-2007 timeframe. As both Edison and PG&E have pointed out, the lead times necessary to sign up for the program and to construct any necessary line extensions mean that almost no additional load is likely to result from the program during summer 2005. The estimates of how much additional load can be expected in the summers of 2006 and 2007 depend on the assumption one makes about the success, or participation, rate of the program with eligible customers. PG&E's updated testimony shows that even assuming a 100% participation rate among eligible customers in its service territory, the additional load can be handled with the surplus that the CEC expects PG&E to have. (Ex. 1, pp. 5-1 to 5-2.) If one uses the 50% participation rate assumed by CFBF (which seems to us more realistic), the available surplus is even larger. (Ex. 6, pp. 2-3.) The evidence shows that because of its smaller population of diesel engines, reliability concerns in Edison's service territory are even smaller. (Id.; Ex. 3, pp. 2-3.)

Although both TURN and ORA agreed that the engine conversion program would improve air quality, and that any reliability concerns could be managed, their testimony raised serious issues about the cost-effectiveness of the program as it was originally proposed.  As noted in Section B, TURN was concerned that the flat line extension adders proposed by the utilities ($32,395 for PG&E customers, $29,942 for Edison's) would result in ratepayers paying widely varying amounts for NO_X reduction, and could lead to "gargantuan" increases in line extension spending for agricultural customers.  ORA was concerned that the proposed rate reduction (20% for PG&E agricultural customers, 12.5% for Edison's) resulted in a negative CTM, contrary to the assertions of the utilities.

The Joint Settlement addresses all of these concerns in a straight-forward way.  By tying the amount of the line extension adder to the size of the replacement electric engine, the settlement addresses TURN's concern that the size of the adder ought to be linked to the amount of NO_X reduction that the engine conversion achieves.  The sliding scale of adders the parties have agreed upon ($7500, $15,000, $32,395) also has the virtue of administrative simplicity, which was not true of ORA's proposal.¹⁴

The Joint Settlement's provision for adders based on engine size also appears to address ORA's concern that the original utility proposals would result in double-digit negative CTMs.  ORA's testimony stated that it proposed to limit the total line extension payments for engines under 400 kW because "the 1000 foot limit essentially eliminates the double-digit CTMs for all of the smaller pumps except those that are 50 kW."  It appears that the more direct approach reflected in the settlement - i.e., tying the amount of the adder to engine size - also serves to eliminate double-digit negative CTMs. 

The limitation on total line extension capital spending for engine conversions addresses another of TURN's concerns.  As noted above, TURN's testimony had expressed alarm about the potential for "gargantuan" increases in line extension spending, in view of PG&E's estimate that its spending for line extensions for agricultural customers was likely to increase from $1.5 million annually to somewhere between $34 and $127 million annually.  TURN's solution to this was to cap total spending for such line extensions at $40 million.  The spending limitation the parties have agreed upon in paragraph 6 of the Joint Settlement, $36.67 million, is close to that figure, and its components -- $27.5 million for PG&E, $9.16 million for Edison - reflect the fact that there are about three times as many eligible engines in PG&E's service territory as in Edison's.  (April 7 Transcript, p. 36.)

Two other aspects of the Joint Settlement deal with competitive concerns raised in TURN's testimony. First, as noted above, TURN was worried about the possibility of stranded investment in the event a municipal utility or irrigation district took over, at some point during the 10-year period the discounted incentive rate was in effect, a territory serving customers who had switched from diesel-powered engines to electric ones. TURN argued that if such a takeover occurred, the utility's shareholders should be required to pay half of the rate discounts received by the conversion customers back to ratepayers. (Ex. 5, pp. 10-11.) Paragraph 8 of the Joint Settlement deals with this possibility by requiring that if a conversion customer departs from the utility's system "within ten years from the date of the [engine conversion] agreement to take distribution service from another provider, the customer will be required to reimburse the utility for the amount of the adder and the difference between rates paid under the [engine conversion] tariff and rates under the otherwise applicable tariff." In light of the whole settlement agreement, we consider this a fair resolution of the stranded investment issue that TURN has raised.

Paragraph 10 of the Joint Settlement deals with a special case of TURN's concern about competition between utilities and irrigation districts to serve load. Paragraph 10 limits to 100 the number of conversion program participants in the portion of the South San Joaquin Irrigation District located in southern San Joaquin County. At the April 7 hearing, TURN witness Nahigian testified that the parties developed this number by determining the ratio between the geographic area of San Joaquin County and the portion of the South San Joaquin Irrigation District that lies within that county, and then applying that ratio to the number of eligible engines within the county. Using this approach and a population of 420 eligible engines county-wide, the parties determined that the limit should be 100. (April 7 Tr., pp. 37-38.) We also consider this approach reasonable.

As noted above, paragraph 5 of the Joint Settlement provides that the commencement date of the agricultural engine conversion program is to be the effective date of the Commission's approval of the Joint Settlement. When the ALJ's proposed decision (PD) was mailed to the parties on May 25, the matter was placed on the agenda for the Commission's June 16, 2005 business meeting. However, in the joint comments on the PD that they filed on June 6, 2005, the parties to the Joint Settlement have now requested that the effective date of the program be deferred until August 1, 2005. They present the following justification for doing so:

"While the utilities' efforts to implement the diesel engine conversion program will certainly commence as of June 16, 2005, if that is the effective date of a Commission decision approving the Joint Settlement, additional time will be required (1) for the utilities to prepare and file final tariff sheets and agreements, (2) for the Energy Division to verify compliance with the Commission's decision . . ., (3) for the utilities to develop and test the required billing system changes to insure accurate bills, (4) for the utilities to finalize line extension training and all customer contact scripts and procedures, (5) for inter-agency coordination of diesel engine disposition, emission reduction transfers, and electric motor testing, and (6) for the utilities, AECA, CFBF, as well as air pollution agencies, to communicate details of this program to potential customers." (Joint Comments, p. 3.)

These are all good reasons for delaying the effective date of the program for approximately 45 days, so the ordering paragraphs of this decision provide that the effective date of the engine conversion program shall be August 1, 2005.

One final issue that needs to be mentioned is the request by both PG&E and Edison that the Commission grant an exemption from Pub. Util. Code § 851,¹⁵ pursuant to § 853(b),¹⁶ for the transfer to CARB or local air districts of the emission reductions that will be obtained from customers as a result of the engine conversion program. (Ex. 1, pp. 1-6 to 1-7; Ex. 2, p. 10.) In their joint April 29, 2005 brief supporting the exemption request, PG&E and Edison argue in support of the exemption as follows:

"In this case, there is no public interest served by subjecting the transfer of emission reductions to Commission review under section 851. The transfer will not affect, in any way, the utilities' ability to provide service to their customers. Indeed, the utilities do not currently own the emission reductions and would only acquire them as part of this program to reduce the use of diesel engines in California. Transferring the emission reductions to the environmental agencies would accomplish the objective of permanent air quality improvements without having any impact whatsoever on the utilities' ability to serve their customers. Therefore, PG&E and [Edison] request that the Commission exempt the transfer from the requirements of section 851." (April 29 Joint Brief, p. 4.)

We agree with this analysis and will grant the requested exemption. As PG&E and Edison point out, the Commission has recently granted such requests in cases where no public interest would be served by subjecting a proposed utility transaction to Commission review. In D.04-03-020, for example, we granted Lodi Gas Storage L.L.C. (Lodi) an exemption from § 851 for the purpose of assigning its accounts receivable to secure a $5 million short-term working capital line of credit, as well as a larger revolving line of credit. After noting that without the assignment, Lodi would have to pay "300 to 500 basis points (3% to 5%) more for short-term money and be subject to tighter operating provisions and covenants from the lender," we concluded that "it is not necessary to impose § 851 regulation of such financial transactions to ensure the ongoing ability of [Lodi] to perform its public utility operations." (Mimeo. at 2, 5.) In this case, because PG&E and Edison will be obtaining the emission reductions from customers solely as a result of the conversion program, and the assignment of these reductions will bring about permanent air quality improvements without having any impact on the ability of the two utilities to serve their customers, an exemption from the requirements of § 851, pursuant to § 853(b), is appropriate.

"ALJ MCKENZIE: I guess my question was, since the settlement agreement contemplates that . . . the Commission should not . . . revisit during . . . the ten-year life of the agreement, marginal costs or contribution to margin, whether you were satisfied, in view of the other terms of the agreement, that there was likely to be a positive [CTM] from . . . the population of engines you were looking at over the life of the agreement, or you were really looking . . . more at the first year? . . . "MR. DANFORTH: I was taking a one-year window.  I had in the back of my mind that the ten-year window probably would yield negative results, but ORA is willing to live with that in light of the air-quality benefits of the program."  (April 7 Transcript, p. 40.)

"No public utility . . . shall sell, lease, assign, mortgage, or otherwise dispose of or encumber the whole or part of its . . . line, plant, system, or other property necessary or useful in the performance of its duties to the public . . . without having first secured from the commission an order authorizing it to do so."