VII. Transmission
A. Transmission Marginal Costs
Most of the differences between ORA and SoCalGas with respect to transmission marginal costs are the result of different recommendations with respect to the appropriate level of investment to be included in the resource plan. This issue is addressed below in a separate subsection.
However, there is one issue with respect to the appropriate marginal demand measure (MDM) for transmission. The Commission adopted MDM for SoCalGas is cold year throughput. CIG/CMA proposes changing this MDM to a weighted average of three design criteria: extreme peak day, firm service day, and cold year. SoCalGas states that the company would not object to this new MDM because the three elements are the design criteria that SoCalGas uses in planning the transmission system.
ORA submits that there is an insufficient record for purposes of changing the methodology adopted in D.92-12-058. (Re Rate Design for Unbundling Gas Utility Services, 47 CPUC2d 438, 454.) ORA argues there is simply nothing in the record indicating the basis for these estimates other than that they were based on "informed judgement." An estimate based on informed judgement is an insufficient basis for changing a methodology which has been in place for several years. In any event, the initial MDMs were based upon a combination of the utility's system design requirement and equity considerations:
The utilities have chosen to advocate certain MDMs because they represent a combination of the multiple types of peak demand that the utility systems are designed to serve. They also support less extreme demand measures in order to spread costs in a `equitable' manner instead of following cost-causation principles in a strict manner. (Re Rate Design for Unbundling Gas Utility Services, D.92-12-058, 47 CPUC2d 438, 454.)
There is no showing that the equity considerations which led to the adoption of a flatter allocator in 1992 have changed. Consequently, the CIG/CMA proposal is rejected.
B. Resource Plan
The Commission's adopted LRMC methodology requires that transmission marginal costs be based upon a resource plan which looks at the amount of investment required over a 15-year planning horizon to serve incremental demand while maintaining system reliability. The foundation for the resource plan is a fifteen year forecast of demand. SoCalGas relies, as it has in the past, on the most recent forecast of long term demand as set forth in the California Gas Report (CGR).
Since adoption of the LRMC methodology, a trend has emerged in which the transmission resource plan appears to have become a device for shifting costs from the noncore to the core. Decreasing forecasts of load growth over the 15-year planning horizon have led to decreasing investment levels. The lower investment levels lead to lower utility estimates of marginal transmission costs. This results in both lower marginal cost revenues and a greater portion of the revenue requirement being allocated by EPMC. EPMC effectively allocates 90% of the difference between the marginal cost revenues and the revenue requirement to core customers.
The trend of ever decreasing resource plan investments is set forth in the following table. The table begins with the 1993 transmission resource plan of $157 million and shows how it evolved into the current $18 million resource plan. It indicates both projects completed between BCAPs and projects that were dropped because of lower demand forecasts.
TABLE 4
Comparison of SoCalGas
Transmission Resource Plans
($Million)
Adopted 1993 BCAP |
$157.0 |
Unneeded Projects |
$55.9 |
Completed Projects |
$12.6 |
Adopted 1996 BCAP |
$88.5 |
Completed Projects |
$15.3 |
Unneeded Supply Project |
$28.0 |
Unneeded Capacity Projects |
$26.5 |
Cost Estimate Adjustment |
$0.8 |
Proposed 1999 BCAP |
$18.0 |
The table indicates that, over a six-year period, the fifteen year resource plan has decreased from $157 million in 1993 to $88.5 million in 1996 and to $18 million in this proceeding. This reduced level of investment results in a significant reduction in transmission marginal costs from $0.09175/Dth ($1996) to $0.06154/Dth ($1999). The cost allocation impact of this reduction in transmission marginal costs is a shift of $28 million from the noncore to the core.
ORA submits that the company has failed to meet its burden of justifying such a significant reduction in transmission marginal costs and the corresponding shift in costs from the noncore to the core. ORA recommends that the Commission retain the resource plan adopted in the last BCAP adjusted downward to reflect projects that have been completed. This results in a resource plan of $77.3 million, a reduction of 13% from the resource plan adopted in the last BCAP.
SoCalGas' contention that it will only have to invest $18 million in transmission plant over the next 15 years is simply not credible in light of past investments, in ORA's opinion. In the 12-year period from 1986-1997, SoCalGas invested $194 million in resource plan type capital projects, an average expenditure of over $16 million per year. Now it would have the Commission believe that it will only spend $18 million over an entire 15-year period.
Except for projects that have been completed since the last BCAP, the entire reduction in the level of investments is premised on a long-term demand forecast which shows a lower rate of growth. SoCalGas does not adequately explain the reasons for the lower forecasted level of demand growth, nor does it explain the reasons for reduced demand forecast. It simply notes that the forecast for 2013 is 105 BCF lower that the forecast upon which the 1996 resource plan was based. Given the reservations expressed by the Commission in the last BCAP over long-term demand forecasts, ORA submits that the company has failed to meet its burden in justifying a $28 million shift in costs that results from a resource plan premised on an unsupported long-term demand forecast.
Rather than justifying its long-term demand forecast, ORA says the company simply takes the lower level of demand growth as a given and then claims that the current level of excess capacity, 25% under cold year conditions and 32% under average year conditions, is sufficient to get it through the next 15 years with only $18 million in resource plan investments.
In any event, the mere existence of excess capacity does not justify such a significant reduction in the resource plan. Excess capacity became a reality upon the completion of the Kern/Mojave project in 1992 and the PG&E Expansion in 1993. Notwithstanding this excess capacity, the company continued to invest in resource plan type projects spending approximately $42 million over just a four-year period from 1994 through 1997. The contention that SoCalGas, the largest gas local distribution company in the United States, will only have to spend $18 million over the next fifteen years is not credible given recent past investments during a period of significant excess capacity.
ORA views the most troubling aspect of the current resource plan to be the absence of the Adelanto project. In the last BCAP, SoCalGas proposed this $28 million project notwithstanding that system capacity exceeded forecasted level of cold year demand. While the project provided some peak day reliability, its primary justification was in providing customers additional flexibility through access to cheaper incremental gas supplies from Canada and the Rocky Mountains. SoCalGas agrees that this is still the ideal location for accepting incremental gas supplies but only if customers are willing to commit to the capacity.
ORA contends that removal of the Adelanto project from the resource plan is unreasonable even if one accepts the accuracy of the revised demand forecast in the 1998 CGR. There is already high level of usage at Wheeler Ridge. This high level of usage has led to forced reductions in nominations. This in turn has limited customer access to supplies from Canada and the Rocky Mountains. The Commission, in supporting the addition to new interstate capacity to California, believed that all customers would benefit from the gas-on-gas competition that would result from excess capacity. ORA argues that the very existence of Wheeler Ridge constraints in the absence of the Adelanto project is evidence that the 300 MMcf/d of incremental capacity provided by the project is still needed.
SoCalGas argues that its transmission resource plan looks at the capacity required on an annual basis first. It says there is over 30% of excess capacity leading into Southern California right now which is more than enough capacity to serve the demands of the customers. The system on an extreme peak day and a firm service day has the pipeline capacity to redeliver gas to customers. There is enough capacity to serve the customer's demands. Overall, incremental capacity is not needed to meet the forecasted system requirements over the next 15 years except for the system constraint in the Moreno station to Rainbow station segment of the SoCalGas system (Line 6900). A capacity expansion of approximately 17 miles of 30-inch pipeline is required to prevent curtailments of firm customers. The estimated cost for this expansion is $18 million.
SoCalGas compared this cost of $18 million over the next 15 years to the SoCalGas transmission resource plan approved in the 1996 BCAP. There were four projects in the 1996 BCAP transmission resource plan which have not been built, and are no longer necessary to meet the updated demand forecast.
C. Line 6900
The only capital investments included in the SoCalGas resource plan are the Phase 3 and 4 expansions of Line 6900 at an estimated cost of $18 million. No party challenges the need for these facility additions. However, several parties claim that the project is driven by demand growth on the SDG&E system and recommend that the costs be removed from the transmission plan and reassigned. SCGC recommends including the costs in SDG&E's resource plan. CIG/CMA recommends assigning 91% of the marginal costs to SDG&E and customers in Mexico and 9% to SoCalGas. Long Beach recommends assigning all of the costs to SDG&E's international border (IB) tariff. ORA agrees with SoCalGas that these facilities should be included in its resource plan.
The history of this issue is set forth in great detail in recent decisions and the testimony of several parties. ( See D.98-03-073, pp. 108-113.) Suffice it to say that, prior to the 1993 BCAP, Line 6900 was treated as an exclusive use facility of SDG&E and it was assigned 100% of the costs. In the 1993 BCAP, the Commission approved a joint recommendation of SoCalGas, SDG&E, and ORA which treated Line 6900 as a common use facility. The costs associated with future expansions of Line 6900 were included in SoCalGas' resource plan. (Re Southern California Gas Co., D.94-12-052, 58 CPUC2d 306, 349.) The costs of expanding Line 6900 were also included in SoCalGas' resource plan approved in the 1996 BCAP although we expressed concerns about whether it was appropriate to include these costs in SoCalGas' resource plan as opposed to SDG&E's. Based on the record in this proceeding, ORA is of the view that the costs are appropriately a part of the SoCalGas resource plan.
SoCalGas asserts that Line 6900 is part of an integrated pipeline network designed to meet the growing retail and wholesale demands in southern Riverside and San Diego counties. The proposed expansion of Line 6900 is designed to serve approximately 100,000 new SoCalGas customers as well as additional wholesale demand from SDG&E, including service to Rosarito. Since these facilities are designed to meet load growth on both the SoCalGas and SDG&E systems, they are appropriately treated as common facilities and should be included in the SoCalGas resource plan.
SCGC (as well as Long Beach and CIG/CMA) opposes the inclusion of Line 6900 in SoCalGas' resource plan. It argues that notwithstanding SoCalGas' claims to the contrary, the record reveals that Line 6900 expansion is driven by growth in SDG&E's noncore load, especially new EG customers located near the California-Mexico border. Moreover, the primary beneficiaries of SoCalGas' proposed treatment of Line 6900 are SDG&E and its customers, while SoCalGas' wholesale and retail noncore customers, especially EG customers, stand to suffer significant harm. Accordingly, SCGC urges the Commission to reject SoCalGas' proposal and include Line 6900 in SDG&E's resource plan.
D. Impact of the Joint Recommendation
The JR would resolve the transmission resource plan and marginal cost issues through adoption of a compromise. The JR recommends a SoCalGas transmission resource plan of $32.5 million. The resource plan would include both the Line 6900 additions of $18 million and 50% of the costs (or $14.5 million) associated with Adelanto project. The Adelanto project was included in the 1996 resource plan and dropped from the current one. This facility addition would provide incremental access to Canadian and Rocky Mountain supplies. The 50% allocation is based upon the assumption that there is a 50% probability that the facility would be required at some point over the 15 year planning horizon. This assumption is clearly reasonable given the current problems associated with Wheeler Ridge constraints which can only worsen over the planning horizon in the absence of this project.
There is always uncertainty in any planning process. Predictions are a function of probabilities. Given this inherent uncertainty, basing the resource plan on a 50% probability that Adelanto will be needed is reasonable. Adoption of the JR would result in a transmission marginal cost of $0.0653/Dth. It is somewhat higher than the $0.06154/Dth marginal cost proposed by SoCalGas and lower than the ORA marginal cost of $0.1242/Dth. It is also lower then the TURN estimate of $0.08963/Dth. The net result is a 30% reduction in the transmission marginal cost adopted in the last BCAP.