III. The Joint Recommendation
SoCalGas, ORA, TURN and CIG/CMA met to negotiate a mutually acceptable outcome to many of the most contentious issues in this proceeding. These efforts led to the development of the Joint Recommendation (JR) submitted into evidence as Exhibit 169-A (Appendix A). The JR would resolve each of the following issues: (1) the length of the BCAP period; (2) the throughput forecast; (3) the degree of balancing account protection associated with the throughput forecast and any discounting needed to retain load; (4) the transmission resource plan; (5) the marginal cost methodology for each of the four functional categories; (6) the appropriate core reservations for interstate capacity and storage; (7) the level of risk for the unbundled noncore storage program; and (8) cost allocation issues relating to Hub revenues, the Direct Assistance Program, and certain competitive load growth opportunities.
After negotiations the Joint Recommendation was presented to other parties for their consideration. SDG&E, Chevron, Texaco, and Vernon joined the Joint Recommendation. Three other parties, SCE, SCGC, and WHP, filed testimony opposing all or part of the JR. They generally argue that since they were not part of negotiations and since their positions were not adopted, the JR should be rejected. The JR is offered for the Commission's consideration as an entire package rather than as a series of discrete issues. The parties supporting the JR believe that the package, as a whole, represents a reasonable compromise of the competing interests, is in the public interest, and should be adopted without modification.
While the parties to the JR support its adoption as the preferred outcome on the issues it addresses, each party also litigated, on an independent basis, each of the issues before the Commission.
ORA's brief contains an excellent summary of the JR, which we have used extensively in describing its various elements. We adopt the JR for the reasons stated below.2
A. Overview of the Joint Recommendation
1. BCAP Period
One of the more basic issues resolved by the JR is the length of the BCAP period. SoCalGas, ORA, and TURN all recommended a three-year period to align the end of the BCAP period with the end of the current Performance Based Ratemaking (PBR) cycle. CIG/CMA and others recommended the traditional two-year period. The JR would adopt a three-year period, January 1, 2000 through December 31, 2002.
2. Throughput Forecast
Another hotly contested issue was the throughput forecast to be used to set rates. Only ORA and SoCalGas presented complete forecasts. SoCalGas based its forecast on a single year, 1999, while ORA used a three-year forecast to coincide with the three-year BCAP period. ORA forecast considerably more throughput for the electric generation class.
In response to a ruling by the ALJ, SoCalGas submitted a revised forecast based on a three-year forecast period. The revised forecast was considerably lower than the single year forecast based upon 1999 throughput. Most of the intervenors supported ORA's higher forecast. The JR would adopt a forecast which is somewhat higher than the forecast contained in SoCalGas' initial showing (932.2 MMdth) and significantly higher than the revised forecast produced in response to the ALJ ruling (896.8 MMdth). The adopted forecast is 950.3 MMdth, which includes 24.9 MMdth added to the noncore demand forecast to account for international border service.
3. Noncore Risk
In conjunction with adopting a higher throughput forecast, the JR would also reinstitute the 75/25 balancing account protection for noncore revenue that was in place prior to the adoption of the Global Settlement for both throughput variation and lost revenue resulting from discounting. ORA, TURN, CIG/CMA and other parties had initially opposed a return to balancing account protection.
4. Transmission Resource Plan
The transmission resource plan is a critical element in calculating transmission marginal costs. The resource plan essentially determines how much investment is needed over the next 15 years to satisfy growth in demand. In its 1996 BCAP, SoCalGas forecast a need to invest $88.5 million over the next 15 years to meet growth in demand. This forecast was adopted by the Commission. In this BCAP SoCalGas has lowered that forecast to $18 million based on a lower forecast of long-term demand growth. ORA and TURN argued that this resource plan was too low and amounted to little more than a manipulation of the long term demand forecast in order to shift costs from the noncore to the core. ORA recommended retaining the resource plan from the last BCAP adjusted downward to account for completed projects. This would result in a resource plan of approximately $77 million. TURN recommended including a single project from the last resource plan, the Adelanto project, which would increase the resource plan to $42 million. CIG/CMA and other noncore interests took the position that even the $18 million plan sponsored by SoCalGas was too high because it was based upon a project, Line 6900, which was more appropriately assigned to SDG&E. They essentially argued for a resource plan which included zero load growth related capital additions over the next 15 years. The JR would adopt a resource plan of $32.5 million which is the half-way point between the resource plan proposed by SoCalGas and the one proposed by TURN.
5. Marginal Cost Methodology
The two major marginal cost issues related to the ORA and TURN proposals are to replace the rental method for calculating marginal customer costs with the NCO method and to include a replacement cost adder for the demand related functions of transmission, distribution, and storage. SoCalGas and other noncore interests opposed both the NCO method and the replacement cost adder. The JR would adopt the NCO method, which is the current method adopted for PG&E, SDG&E, and SCE, while rejecting the replacement cost adder. It would also adopt several other less significant compromises on marginal cost issues including TURN's estimate for the Administrative and General (A&G) loader factor as well as TURN's estimate for medium pressure distribution investment.
6. Core Interstate Capacity and Storage Reservations
SoCalGas proposed increasing the core's interstate capacity reservation from 1044 MMcfd to 1076 MMcfd based upon a forecasted increase in the core's cold year demand forecast. The higher reservation would cost core customers an additional $4 million per year. ORA recommended maintaining the reservation at its current level because of the excess of interstate capacity and the availability of supplies at the California border during periods of peak demand. ORA also recommended eliminating the core's responsibility for ITCS costs largely because of the significant benefits noncore customers have received as a result of SoCalGas' relinquishment of capacity on El Paso Natural Gas Company (El Paso) and Transwestern Pipeline Company (Transwestern), estimated to be in the range of $300-$500 million on a present value basis. Elimination of the core's ITCS responsibility would shift approximately $9 million in ITCS costs to the noncore. TURN supported both of ORA's recommendations, while SoCalGas and noncore interests opposed them. As a compromise the JR would resolve this issue by maintaining the status quo with respect to the core interstate capacity reservation. In addition, the core would continue to be responsible for its historical share of ITCS costs. This outcome has no impact on cost allocation since it simply retains the current allocation.
SoCalGas also proposed increasing the core's storage withdrawal capacity reservation from 1985 MMcfd to 2082 MMcfd based upon its estimate of the core's peak day requirement. ORA recommended retaining the reservation adopted in the last BCAP because of the availability of flowing supplies to meet the difference between the current reservation level and peak day requirements which are expected to occur only once every 35 years. TURN recommended lowering the reservation based on a higher estimate of the amount of flowing supplies available on a peak day. Noncore interests sided with SoCalGas in opposing both the ORA and TURN proposals. The JR would compromise this issue by adopting a withdrawal reservation of 1935 MMcfd. This represents the midpoint between the TURN and SoCalGas positions. Lowering the reservation by this amount would increase the amount of withdrawal capacity available for the unbundled storage program.
7. Unbundled Storage Program
Both ORA and WHP recommended eliminating the balancing account protection applicable to the unbundled storage program in order to level the playing field between the incumbent provider of storage services and potential competitors such as Lodi Gas Storage and Wild Goose. ORA and WHP also recommended granting the utility some pricing flexibility in return for the increased risk. SoCalGas indicated that it was amenable to being placed at risk if certain conditions were met, including some pricing flexibility. However, it recommended resolving this issue in the Gas Industry Restructuring proceeding.
The JR would take some interim steps toward a level playing field. The level of shareholder risk would be increased by reducing the current level of balancing account protection to 50/50. In addition, SoCalGas would be granted some pricing flexibility with a cap equal to 120% of the ceiling reservation charges set forth in its tariffs. The costs allocated to the unbundled storage program would be set at $21 million rather than the fully scaled amount of $32 million. The $21 million that would be allocated to the noncore storage program is close to both the embedded cost of the facilities and the unscaled marginal costs. The $11 million difference would be allocated to the Noncore Storage Balancing Account (NSBA) along with other stranded costs. The balance in the NSBA would be recovered from all customers on an equal-cents-per-therm basis.
8. Cost Allocation Associated with Core Deaveraging, Hub Revenues, the Direct Assistance Program, and Incremental Load Growth Opportunities
The JR would also resolve a number of other cost allocation issues including core deaveraging, the allocation of Hub Revenues, the recovery of Direct Assistance Program costs and the treatment of incremental load growth resulting from shareholder funded discounts.
a. Core Deaveraging
In each of the last two BCAPs, the Commission has made progress in eliminating the effects of averaging residential and commercial rates. To date, 75% of the effects of averaging have been removed from commercial rates. Both SoCalGas and ORA proposed fully eliminating the effects of averaging during this BCAP period. This would shift an additional $28 million in costs from commercial to residential customers. TURN proposed maintaining the status quo arguing that SoCalGas was already well ahead of other utilities in eliminating the effects of averaging. The JR adopts the TURN recommendation to maintain the status quo.
b. Hub Revenues
Currently revenues generated from SoCalGas' Hub services are used to reduce the gas costs recorded in the company's gas cost incentive mechanism (GCIM). This is consistent with the finding in the last BCAP that core flowing supplies were essential to the provision of Hub services. (D.97-04-082, pp. 82, 175.) SoCalGas proposed to continue that treatment in this proceeding while SCGC recommended removing these revenues from the GCIM and allocating them to all customers on an equal percentage of marginal cost (EPMC) basis. The JR would continue the current practice of crediting the revenues to the GCIM. This is the same treatment adopted in D.97-06-061 approving the GCIM mechanism.
c. Direct Assistance Program Costs
SoCalGas proposed allocating $18 million in Direct Assistance Program (DAP) costs to residential customers. TURN recommended allocating these costs in the same fashion as CARE costs, equal-cents-per-therm. An equal-cents-per-therm allocation would shift approximately 60% of these costs, or $10.8 million, to noncore customers. The JR would adopt the SoCalGas position.
d. Incremental Load Growth
The final cost allocation issue addressed by the JR is the SoCalGas proposal to exempt from the cost allocation process for a five-year period incremental growth associated with shareholder funded discounts under the state sponsored Red Team economic development program and the Commission approved Rule 38 program. Normally, additional load from discounted contracts entered into during one BCAP period would be reflected in the throughput adopted in the following BCAP thereby spreading the benefits of the increased load to all ratepayers. ORA opposed this proposal arguing that the move from a two to a three-year BCAP represented a sufficient increase in shareholder incentives. The JR would adopt the SoCalGas position.
B. Adequacy of Representation
WHP argues that the JR must be rejected because WHP, "a major stakeholder" (WHP's characterization), was not represented at the negotiating sessions which led to the JR. SCE and SCGC make much the same argument as WHP. This argument is without merit.
First, WHP's (or any party's) position could have been rejected whether or not WHP was at the negotiating table. Second, WHP was given the opportunity to comment on the JR, seek to modify the JR, and join the JR. It chose to oppose and presented evidence in opposition. We are not persuaded by its evidence.
While not all parties were invited to the table, we believe the wide range of interests were adequately represented and, as a consequence, the JR represents a fair outcome. We agree with ORA's argument that cost allocation is a zero sum game, and that this proceeding is largely a dispute between core and noncore interests over how to apportion the revenue requirement pie to different customer classes. It is clear that the parties to the JR represent many if not all of the various customer groups and other entities affected by the issues addressed by it. SoCalGas represents not only the interests of its shareholders, but also the interests of all its customers, including, but not limited to, the interests of noncore customers. ORA represents the interests of all ratepayers. TURN represents residential and small commercial ratepayers. CIG/CMA represents a host of commercial and industrial interests, including members of the G-30 tariff class which has a distribution segment, and members of the G-50 tariff class. SDG&E and Vernon are wholesale customers of SoCalGas. Chevron and Texaco are large industrial and electric generation customers. This broad spectrum of interests validates and buttresses the reasonableness of the JR.
WHP strongly opposes the JR. It recommends that the Commission reject the "All Other Storage Issues" provisions of the JR; reject the transmission resource plan of the JR; eliminate the NSBA; and change the long-run marginal cost (LRMC) method used in the JR. WHP complains that it was left out of the negotiations which led to the JR; that the JR made fundamental changes to the structure of the storage market "without involving major stakeholders in the discussions leading to the recommended market changes." (WHP O.B. p. 6.)
WHP claims to be a "major stakeholder." That it is a stakeholder, in a sense, is plausible; but that it is a major stakeholder is nonsense. It is not a customer of SoCalGas, it contributes nothing to SoCalGas' revenue requirement, if it succeeds in raising SoCalGas' storage rates it will attempt to take SoCalGas' customers, thereby placing the burden of satisfying SoCalGas' revenue requirement on the remaining core and noncore customers. It is an active party and a competitor. The stake of an outsider is small in comparison to those who have to pay the gas bills. Yet, WHP's interest was represented, in part. Both WHP and ORA recommended eliminating balancing account treatment for noncore storage services while simultaneously granting the company some pricing flexibility. SoCalGas, on the other hand, recommended deferring the issue to Gas Industry Restructuring (GIR). The JR clearly moves in the direction recommended by ORA and WHP.
SCGC and SCE do pay gas bills and are stakeholders. However, their assertion that the JR is fundamentally flawed because they were not at the bargaining table and their interests were underrepresented is without merit. As noted above, we believe a reasonable cross-section of SoCalGas' customers were represented. Further, SCGC and SCE were offered the opportunity to have the parties to the JR consider their issues and interests. But most importantly, parties opposed to the JR were given ample opportunity to refute on the record and in briefs each and every issue resolved by the JR. There is no requirement that all parties in a proceeding must be included in a joint recommendation. Such a requirement would be granting a veto to any party, which is clearly not in the public interest.
We believe the opponents misconceive the nature of a joint recommendation. A joint recommendation, such as the one presented here, is a compromise of positions of some of the parties, which, by its very nature, has no precedential value. It is of assistance to the Commission to the extent that the parties to the recommendation are knowledgeable and have vested interests in the outcome. In this instance it is the reasonableness of outcome that persuades us to adopt the JR.3 The point of a compromise is to avoid deciding the merits of each individual contested issue. Given the variety of views on all issues, we cannot say that an issue by issue determination by the Commission would result in a more accurate prediction of costs, allocations, and rates, than that which is derived from the JR. What we can say is that the JR gives us confidence that major stakeholders with vested interests think it is reasonable.4 Our analysis of the JR leads to the same conclusion.
We note that a number of the issues resolved by the JR also have been raised in our GIR proceeding (I.99-07-003). Because the JR is non-precedential, by approving it we are not limiting the Commission's consideration of those issues in the broader context of the GIR proceeding.
The remaining sections of this decision present an overview of the parties' litigation positions and, where relevant, the manner in which the JR is the preferred solution.
