D0004060

XX. Issues Local to SDG&E

Issues common to both SoCalGas and SDG&E have been addressed in earlier sections of this decision. The common issues include the length of the BCAP and forecast periods, marginal cost methodological issues such as the use of the NCO method for calculating customer marginal cost and the use of replacement costs adders for each of the demand functions, and the proposed single EG rate for both the SoCalGas and SDG&E systems. Issues unique to SDG&E include throughput, the transmission resource plan, customer and distribution marginal cost estimates, and rate design.

SDG&E has entered into two written agreements with interested parties which are intended to narrow the remaining issues. The Joint Recommendation (SDG&E JR) between ORA, SDG&E, and UCAN is by far the more expansive of the two, offering proposed resolutions to virtually all of the disputes between these parties (Appendix B). Specifically, the SDG&E JR resolves various marginal cost and cost allocation issues, agrees upon a transmission resource plan, stipulates to throughput and revenue levels, and proposes a two part, two-tiered volumetric rate design for electric generators served by SDG&E.

The SDG&E JR does not present a proposed resolution to the question of whether the Commission should adopt a Sempra-wide EG rate, nor come to any conclusion on issues related to the Schedule IB tariff proposed in the SDG&E and SoCalGas application for approval of a gas transmission service (A.98-07-005), and rejected in D.99-09-071.

The second joint recommendation is between SDG&E and the Western Mobilehome Parkowners Association (WMA) (the WMA JR) concerning the master meter differential for SDG&E's mobilehome park customers (Appendix C). This is a narrow issue of only limited interest. WMA and SDG&E were the sole presenters in this matter.

SDG&E asserts that together, these two agreements offer a fair and reasonable resolution to the vast majority of disputed issues in SDG&E's 1999 BCAP. The parties ask us to recognize that these agreements were reached through intense negotiation and compromise. Parties were required to compromise their original positions. Accordingly, the parties view each agreement as a unified whole, with individual recommendations expressly conditioned upon Commission acceptance of all other recommendations.

A. Throughput Forecast

The SDG&E JR recommends that the Commission adopt ORA's annual fossil generation throughput forecast of 480 million therms for SDG&E's former UEG customers. This amount falls between the forecast arrived at using production cost modeling and analyzing recorded values. Production cost modeling provides a logical tool for forecasting UEG throughput. The model matches electrical supply with demand over a wide geographic area, and then predicts which facilities will be dispatched based on production costs and reliability requirements.

A trending of future throughput from recorded values offers a historic basis for the forecast. With much of California generation no longer owned by regulated utilities, the operating strategies of the new non-regulated utilities are difficult, if not impossible to model. In fact, there have been so many changes over the past 18 months in the California energy market generally, and with the SDG&E's fossil generation units in particular, that it is difficult to be confident that next year's gas usage will be anything like the prior years' usage.

The radically changing California energy market is reason enough for the Commission to adopt a compromise forecast between production modeling and historic trending. The deregulation of the California electric market dramatically changed the conditions under which electric generators must operate. Today, most generators bid into the competitive market operated by the PX to sell their energy and any associated ancillary services. The ISO has designated some generators as RMR units, meaning that they will be dispatched for reliability purposes if they are not dispatched in the marketplace.

SDG&E's fossil units have been sold to two separate companies, each with its own operating strategy. Given the fundamental transformation of the California market and the recent change in ownership of the SDG&E units, adopting a compromise forecast which is mid-way between production cost modeling and historic trending will achieve a fair outcome.

B. Resource Plan

The SDG&E JR recommends a $31 million gas transmission resource plan for SDG&E. This resource plan is a compromise between SDG&E's original proposal - a $25 million plan - and the $42.7 million plan ORA sponsored. The SDG&E JR adopts a plan that is roughly 25% more expensive than SDG&E's initial proposal and almost one-half of the 49% increase ORA recommended in its report.

C. Marginal Costs

1. Marginal Customer Costs

The SDG&E JR uses the NCO method for calculating customer marginal costs as advocated by ORA and UCAN. The Commission ordered SDG&E to use the NCO method in D.97-04-082, SDG&E's 1996 BCAP decision. The NCO method incorporates three main marginal cost components: (1) a one-time investment cost for new customers; (2) an annual investment cost of replacing customer service, regulator, and metering equipment; and, (3) customer related O&M expenses. The SDG&E JR reflects a compromise between positions originally taken by SDG&E, ORA, and UCAN on capital costs, O&M costs, and O&M loading factors.

The SDG&E JR also incorporates the following specific ORA and UCAN positions for calculating marginal customer costs:

g. Residential Customers

The SDG&E JR adopts UCAN's proposal for calculating marginal customer costs for the residential customer class.

h. Non-Residential Customers

The SDG&E JR adopts ORA's proposed new and replacement capital cost calculations and UCAN's recommended reduction of SDG&E's variable customer costs for: (1) returned checks and field collection charges; and, (2) service establishment fees. The SDG&E JR also adopts UCAN's proposed A&G O&M loading factor.

2. Demand Costs

The SDG&E JR maintains the status quo with regard to the demand-related marginal cost methodologies adopted in D.97-04-082. The SDG&E JR excludes ORA's replacement cost adder proposal for demand related marginal costs (distribution and transmission).

3. Distribution Marginal Costs

The SDG&E JR adopts ORA's proposed distribution marginal cost regression calculations and UCAN's A&G loading factor of 13.995%. The SDG&E JR adopts SDG&E's recommendation to exclude replacement cost adders. By adopting these compromise positions, the SDG&E JR produces lower distribution marginal costs than those originally proposed by SDG&E.

4. Transmission Marginal Costs

To develop transmission costs, the SDG&E JR uses the Commission-adopted methodology from D.97-04-082. Specifically, it adopts the total investment method with no replacement cost adder; assumes a $31 million total resource plan investment for calculating transmission marginal cost; and adopts UCAN's proposed 13.995% A&G loader.

In summary, the SDG&E JR reflects a blend of positions originally taken by SDG&E, ORA, and UCAN with regard to marginal costs, O&M costs, and O&M loading factors related to customer marginal costs. The SDG&E JR addresses UCAN's concern that residential marginal customer costs as proposed by SDG&E are too high. It addresses ORA's concern that some A&G expenses were "double counted" in SDG&E's capital cost calculation. The SDG&E JR also adopts ORA's assumptions concerning NCO replacement rates and replacement costs. And, although SDG&E's 1996 BCAP replacement cost assumptions would produce higher replacement costs under the NCO method than those proposed using the ORA's assumptions, the SDG&E JR adopts the ORA assumptions and calculations as part of the whole package.

D. EG Rate Design

The SDG&E JR produces a stand-alone EG rate design for SDG&E that is distinct and separate from the EG rate design (and EG charges) used by SoCalGas. The proposed rate design would divide SDG&E's EG customer class into two segments, with each part consisting of a single customer charge and two tiers of declining block rates. The "Part A" EG rates are applicable to individually metered EG loads of less than one million therms per month. The first block rate (Tier 1) under "Part A", applies to the customer's first 21,000 therms of usage per month. The second, lower block rate (Tier 2) applies to all excess usage.

The "Part B" EG rates are applicable to individually-metered EG loads equal to, or greater than one million therms per month. The Tier 1 rate under "Part B" applies to the customer's first one million therms each month. The lower Tier 2 rate applies to all excess usage. The SDG&E JR's EG rate proposal is based on the alternate EG ratemaking methodology proposed by SoCalGas adjusted to reflect SDG&E's customer usage characteristics.

Because we are adopting a Sempra-wide EG rate, this part of the SDG&E JR will not be adopted. The parties agree.

E. Sempra-Wide EG Rate

The SDG&E JR does not address the issue of whether the Commission should establish a uniform rate across both SDG&E and SoCalGas' service territories. The parties agree that if the Commission does adopt a Sempra-wide EG rate, the EG rate design of the SDG&E JR may be modified to comply.

F. Rosarito Loads

The SDG&E JR does not address the question of whether Rosarito loads should be included in SDG&E's proposed EG customer class (or an existing SDG&E customer class) for cost allocation purposes. The rates proposed in Exhibit 195 assume that Rosarito loads and costs are excluded. SDG&E concedes, however, if the Commission decides to include Rosarito loads and costs within one of SDG&E's proposed or existing classes, the SDG&E JR's IB class credit should be changed to zero. As we decided in D.99-09-071, the forecasted throughput for service at the international border should be included in both SDG&E's EG forecast and SoCalGas' wholesale forecast.

G. Marginal Cost Calculations

The SDG&E JR maintains the status quo for calculating marginal cost revenues and base margin costs, and for allocating base margin costs and non-base margin costs.

H. Core Deaveraging and Global Settlement Credits

The SDG&E JR proposes to deaverage (referred to as a "capping adjustment" in Exhibit 195, Table IX-2) core commercial rates by 10 percent per year to gradually move all core utility rates closer to their cost of service basis. The SDG&E JR parties further agree to translate this proposal into a fixed revenue amount of $2.291 million per year. This amount reflects the level of dollars transferred each year from core commercial customers, as a group, to residential customers. In D.97-04-082, the Commission adopted core deaveraging as a one-time event. The SDG&E JR proposes to gradually deaverage core rates by 10% per year over three years to mitigate the impact on residential rates.

The Global Settlement credit returns dollars already collected from gas customers on an equal-cents-per-therm basis. This credit account reflects two years of advance collections to pay SDG&E's five-year financial obligation to SoCalGas as specified in the SoCalGas Global Settlement Agreement. The SDG&E JR proposes that the core portion of the credit be returned to core customers through a rate reduction over 24 months and that the noncore, non-former UEG portion be returned to customers in the form of a check or bill credit. The former UEG portion of the credit would be transferred to SDG&E's electric transition cost balancing account (TCBA).

I. CARE and DAP

The SDG&E JR does not propose changing the way SDG&E currently calculates CARE and DAP costs. The existing CARE surcharge is comprised of three components -- CARE program expenses, amortization of the CARE balancing account, and the revenue benefits (i.e., the 15% rate discount provided to participating CARE customers). CARE surcharge costs are recovered from all gas customers, excluding EG customers and participating CARE customers, on an equal-cents-per-therm basis. DAP costs are recovered as a part of SDG&E's base margin costs, and, as such, are allocated to all gas customers on an EPMC basis.

J. Baseline Rates

The SDG&E JR recommends decreasing both the residential baseline and non-baseline rates, and in such a way that reduces the differential between them. Under the SDG&E JR proposal, the non-baseline rate would receive a larger decrease in order to achieve a modest tier closure between the two rates. The SDG&E JR would narrow the difference between the baseline and non-baseline rates from 132% to 128%. Both percentages are measured in terms of the non-baseline as a percent of the baseline rate, and both are measured on a full service basis: i.e., the customer receiving both utility procurement and transportation services.

Narrowing the tier differential in this way provides a 2.9% class decrease and a minimum 1% rate reduction to both the baseline and non-baseline rates, while achieving a modest tier closure between these rates.

K. Master Meter Issues

SDG&E and WMA recommend a fixed unit discount of 31.0 and 23.2 cents per day for customers served under SDG&E's Schedules GT and GS, respectively. Service under Schedules GT or GS is available to master-metered customers in mobile home parks and sub-metered residential units. The parties agree that the use of the rental method of estimating marginal customer costs is appropriate for this purpose. Because we are adopting a settlement we do not approve or disapprove of the allocation method used by the parties.

We note that because this discount is higher than the existing unit discount, the residential rates supported in the SDG&E JR by ORA, SDG&E, and UCAN are slightly impacted. The existing and proposed methods for residential rate design recover this revenue shortfall (caused by providing the space unit discounts) from residential customers only. All other non-residential rates remain the same.

L. Core Commercial and Industrial

The SDG&E JR parties recommend that the Commission adopt a single tariff schedule applicable to all SDG&E's core commercial and industrial (C&I) customers. Doing so would simplify rates and produce lower bills for core C&I customers. The proposed single C&I tariff consists of three tiers of customer charges and three tiers of declining block rates.

SDG&E's core C&I customers are currently served under two tariff schedules: GN-1 for small C&I customers consuming less than 20,800 therms per month (over the past two years or seasons), and GN-2 for all other C&I customers. Both tariff schedules have the same set of charges (i.e., a single service fee and two tiers of declining block rates) but different charge amounts. SDG&E can merge the existing tariffs with minimal changes to the level and structure of the existing charges. And both small and large core C&I customers will see bill decreases, except for small core C&I customers whose consumption is zero.¹⁶

M. Natural Gas Vehicle (NGV) Rates

The SDG&E JR adopts two NGV proposals originally sponsored by SDG&E. The first proposal seeks to equalize NGV rates among two SDG&E NGV customer groups -- one for buses and military fleets and another for all other vehicles. Although both groups receive identical compressed natural gas services from the utility, they are billed under different rates. The existing rate difference reflects pricing signals for NGV that existed prior to the Commission's issuance of the low emission vehicles (LEV) decision D.95-11-035 (62 CPUC2d 395). That decision ordered SDG&E to establish cost-based NGV rates in SDG&E's 1996 BCAP. Since SDG&E's marginal cost calculations do not distinguish between NGV services, a rate difference should not exist. NGV customers should pay the same rate for the same service. If this proposal is adopted, both customer groups will receive double-digit rate decreases.

The second NGV proposal would permit all NGV customers to select transport-only services. Under the existing Schedule G-NGV, SDG&E currently provides four separate NGV services: (a) compressed natural gas service for buses and military fleets; (b) compressed natural gas services for other fleets and vehicles; (c) uncompressed natural gas service for motor vehicles; and (d) natural gas services for co-funded NGV stations. Of these four categories, SDG&E currently provides transport-only services to NGV customers receiving uncompressed gas services under (c). All NGV customers should have the opportunity to participate in transport-only gas services, particularly since these services are currently available to all other (non-NGV) gas customers, both core and noncore. Accordingly, the SDG&E JR makes transport-only gas services available to all NGV customers. This proposal is reasonable and will be adopted.

N. Noncore Rate Design

The SDG&E JR retains the existing rate design for SDG&E's noncore commercial and industrial (noncore C&I) customers. Noncore C&I customers are currently segmented by three service levels -- transmission-only (TLS), high-pressure distribution service (HPS), and medium-pressure distribution service (MPS). Each segmented service has the same rate design consisting of six tiers of customer charges and seasonal volumetric rates, with the winter season lasting four months beginning in December. The SDG&E JR proposes no modifications to this rate design.

The SDG&E JR proposes no changes to the six tiers of customer charges, but recommends a 25% increase (equal to $25), to the automatic meter reading (AMR) charge. In addition, the noncore C&I volumetric rates are revised on an equal percent of revenue basis.¹⁷ This proposal is reasonable and will be adopted.

O. Schedule XGTS

The SDG&E JR proposes that SDG&E eliminate gas services provided under Schedule XGTS. In support of this change, SDG&E says that Schedule XGTS is an experimental tariff that has failed. Schedule XGTS was adopted in SDG&E's 1993 BCAP decision (D.94-12-052, 58 CPUC2d 306) as part of a settlement between SDG&E and DRA (the former ORA). The decision offered experimental Schedule XGTS to introduce the concept of real time pricing (RTP) to gas customers. The SDG&E JR parties advocate terminating the experiment.

SDG&E asserts that Schedule XGTS rate design ensures a revenue shortfall. There are two reasons for this result. First, the off-peak rate under XGTS is set substantially below SDG&E's marginal cost of transmission service, which is approximately one cent per therm.¹⁸ As a result, SDG&E incurs a revenue shortfall for every therm of gas billed under the XGTS off-peak rate. And, secondly, the frequency of on-peak billing under XGTS has been substantially less than its rate design parameters, resulting in substantially less therms billed at the on-peak rate than anticipated. Billing records reveal that on-peak billing under XGTS occurred only 163 hours over a four and one-half year period, or approximately 1.8 days per year. The rate design parameters for on-peak billing under XGTS assume an annual billing occurrence of approximately 20 days per year. As a result, more therms have been billed under the XGTS off-peak rate than expected, leading to greater revenue shortfalls. These revenue shortfalls will continue to grow if load participation under XGTS is expanded.

Monsanto recommends that SDG&E expand service under XGTS to include EG loads. The SDG&E JR parties oppose this proposal because increasing the load participation under XGTS, without also changing the rate design flaws, will simply result in higher revenue shortfalls. Revenue shortfalls under XGTS receive 100% balancing account treatment, and are allocated to remaining noncore customers. A continuation or expansion of shortfalls under XGTS will simply increase noncore C&I and EG rates and effectively prolong a subsidy of utility services provided to one customer at the expense of all noncore customers.

Even allowing EG customers to take service under XGTS would not achieve the objectives SDG&E originally envisioned. As SDG&E stated, at least 25% of existing EG loads would have to take service under XGTS to achieve a key objective: to entice enough load participation so that future investments in capacity additions could be deferred. Based on the volumes adopted in the SDG&E JR, a 25% EG load participation would equal approximately 162 million therms annually.¹⁹ SDG&E had hoped that the initiation of on-peak price signals under pre-curtailment situations would encourage enough customers, particularly large gas users, to voluntarily reduce their gas use during an on-peak event, and thereby reduce the frequency of, or even the need for, usage mandated gas curtailments.

The only way to achieve the necessary participation level of 162 million therms per year would be to attract either all forecasted cogeneration loads (approximately 51 customers using a total of 169 million therms per year) or a significant portion of former UEG loads to take service under XGTS. The former scenario is not possible since only two or three of SDG&E's largest cogeneration customers have the capability to shift sizeable loads from their business operations on an hourly basis. And, only another two or three of the largest customers would find it cost effective to make the capital investment necessary to shift gas loads on an hourly basis.

The latter scenario is no longer probable, in SDG&E's opinion, because the two large, former UEG customers (i.e., South Bay and Encina power plants) now operate as RMR units. An RMR unit must maintain a certain operational minimum to meet customer electric demand if such demand is not met by the marketplace. As a result, an RMR unit is not likely to take service under XGTS because its RMR obligations could prevent it from reducing loads during an XGTS on-peak price signal event. With high on-peak rates under XGTS, a large gas user would be unwise to sign up for XGTS if they could not reduce significant loads during a XGTS on-peak price signal event. Currently, the two largest gas users on the SDG&E system, which comprise approximately 40% of system loads on average, are RMR customers and unlikely candidates for XGTS.

Lastly, there is only one customer currently receiving service under XGTS. Consequently, eliminating XGTS will not cause a substantial revenue shift relative to system revenues. The billing revenues received from this customer total approximately $2 million, or less than one percent of total SDG&E system revenues.

We agree with the SDG&E JR and will adopt it with the modification to provide for the Sempra-wide EG rate.

¹⁶ The current service fee for small core C&I customers is $5 per month. The proposed single tariff fees for this group of customers remain at this level. ¹⁷ While this proposal is not explicit in the SDG&E JR itself, rates that result from Exhibit 195 (Table X-6, column E) confirm a revision of rates computed on an equal percent of revenue basis (i.e., each volumetric rate change is made on the same percent basis). ¹⁸ SDG&E had an off-peak rate of 0.661 cents per therm, which was the current tariff rate under XGTS prior to January 1, 1999. Since that time, SDG&E has revised its rates in compliance with a new cost of service adopted for SDG&E (D.98-12-038) and a revision to SDG&E's unbundled transportation rates, where XGTS is an unbundled transportation tariff, pursuant to CPUC Resolution G-3248, dated February 4, 1999. These revisions have reduced the XGTS off-peak to 0.463 cents per therm. ¹⁹ SDG&E estimated a 25% level of EG participation at 139 million therms per year. This number was based on SDG&E's proposal for an annual forecast of 44 bcf for its former UEG loads. Since the SDG&E JR adopted ORA's annual forecast of 48 bcf for SDG&E's former UEG, the minimum 25% participation level would increase, all other things being equal.