COM/RB1/rmn |
ALTERNATE DRAFT |
H-1b |
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11/21/2000 | |||
Decision ALTERNATE PAGES TO H-1a OF COMMISSIONER BILAS
(Mailed 11/6/00)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
Application of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) to: (1) Consolidate Authorized Rates And Revenue Requirements; (2) Verify Residual competition Transition Charge Revenues; (3) Review the Disposition of Balancing and Memorandum Accounts; (4) Review Generation Cost Jurisdictional Cost Allocation; (5) Review the Reasonableness of the Administration of the Low Emission Vehicle Program; (6) Review the Administration of Special Contracts; and (7) Present a Proposal for the Inclusion of Long Run Marginal Costs in the Power Exchange Energy Credit. |
Application 99-08-022 |
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And Related Matters. |
Application 99-08-023 (Filed August 9, 1999) |
(Appearances are listed in Appendix A.)
In this decision we adopt a Power Exchange (PX) credit adder of 0.014 cents per kilowatt-hour (cents/kWh) for San Diego Gas & Electric Company (SDG&E), 0.036 cents/kWh for Pacific Gas & Electric Company (PG&E), and 0.030 cents/kWh for Southern California Edison Company (Edison). We find that it is unreasonable to exempt wholesale customers from paying their fair share of Reliability Must-Run (RMR) costs and we put Edison on notice that retail ratepayers will not bear the burden of 100% of the RMR costs in the future. We discuss the confusion regarding the definition and computation of long-run marginal costs (LRMC), and hold that the proper method for determining the PX credit is by use of long-run marginal costs, as adjusted for bulkiness, which was closer to the method used by ORA and ARM.
I. Background and Procedural History
In our opinion on Cost Recovery Plans, Decision (D.) 96-12-077, we recognized the need to streamline utility cost recovery mechanisms to effectively implement a restructured electric utility industry in accordance with Assembly Bill No. 1890 (AB 1890). Accordingly, we created the Revenue Adjustment Procedure (RAP) to review, track, and compare each utility's authorized revenue requirements with actual recorded revenues and to approve any necessary adjustments or updates to authorized revenues. Such adjustments are associated with the performance-based ratemaking (PBR) mechanism and decisions addressing such issues as power purchase contracts, public purpose programs, nuclear decommissioning, and transition costs.
A number of issues were added to the 1999 RAP by D.99-06-058, the first RAP:
1. The elimination or retention of memorandum and balancing accounts,
2. The costs associated with low emission vehicles, and
We find that ORA's numbers for SDG&E should be reduced by $0.213 million or 10 percent. This would result in a PX credit adder for SDG&E of about 0.013 cents/kWh.
Regarding PG&E, we again note that ORA was not required to perform a specific LRMC study. ORA did use SCE figures to calculate PG&E's credit; this is a concern that we will address below. However, ORA's proxy analysis can still be considered as it stands. It is probably true that all activities performed by the customer service representatives and account managers are not procurement related (e.g., correcting billing errors, handling new service requests). However, the 1998 RAP decision D.99-06-058 (p. 24) anticipates that costs related to these activities should be included in the PX credit. At present, since PG&E did not provide us with the proper cost studies, we will reflect changes from ORA's recommendation for PG&E based on our approach to Edison, below. Therefore, we will reduce ORA's recommended PX credit for PG&E by 30%, to 0.034 cents/kWh.
Regarding Edison, if only $4 million of the ES&M costs that ORA includes are related to procurement, and the rest are supply related, then ORA's PX credit should be reduced by about $8.3 MM or about 30%. We will reduce ORA's recommended PX credit for SCE by 30 %, to 0.028 cents/kWh.
Regarding ARM, we note that ARM generally asserts that ORA could have included more costs in its PX credit calculation. This could offset the decrements to ORA's costs that the UDC's cite. We believe it is likely that ORA did in fact miss certain costs that might have been included in the credit. Because of different methodologies, it is not possible to add in costs identified by ARM to ORA's numbers. However, it is reasonable to find that ORA's figures do not include all possible costs applicable to the calculation of the credit.
A. Adopted Analytical Methodology
We have already rejected the utilities' arguments that the long-run marginal costs of procurement are zero or near zero. The utilities in reality
conducted short-run marginal cost analyses and generally did not consider how its factors of production would change in the long run if it served fewer customers.
The key concept to consider in determining the correct total cost curve for the UDC is bulkiness. A typical cost curve starts at zero and moves upward. Here we start at the highest level of kWh and remove blocks of lumpiness. The total costs of the UDCs do not decrease in a true parabolic curve like a typical cost curve. That is because the total cost curve follows stepped output blocks of kW hours. Each step is identified as the point at which there is enough total cost impact of a block of kW hours leaving the system. At each such step point, total cost falls in discrete steps. Moreover, the correct parabolic total cost curve, due to this bulkiness, fits along the mid points of each block rather than the top of each stair step. A regression analysis on output kWh and costs, conducted along these mid points, produces the correct total cost curve. Although not precisely configured along these lines, the ORA and ARM studies comport more closely to such a bulkiness analysis than do the UDCs' studies.
Both ORA and ARM presented much more complete and appropriate studies. ORA's list of cost categories presents a good basis for analysis of procurement costs. The utilities criticize ORA and ARM for certain imperfections in their methodologies. However, due to the lack of responsiveness by or information from utilities, ORA's overall methodology provided conservative figures by leaving out certain costs that likely belong within the PX credit. While ARM's studies provide a good basis for a determination of the credit and could be adopted, we believe ORA's detailed and comprehensive studies provide a slightly better basis for establishing the credit.
To the extent that ORA or ARM are incorrect and have overstated costs in any way, accepting ORA's lower figures protects both ratepayers and utilities from error.
We will modify ORA's recommended credits based on the discussion above. ORA's adjusted numbers based on the UDC's criticism that should be accepted are: SDG&E: 0.013 cents/kWh; PG&E: 0.034 cents/kWh; and Edison: 0.028 cents/kWh. Because we find that ORA's figures do not include certain costs as discussed by ARM, we will increase these figures slightly to SDG&E: 0.014 cents/kWh; PG&E: 0.036 cents/kWh; and Edison: 0.030 cents/kWh.
We do not believe that a uniform rate should be used at this time. While it is true that having one uniform rate in all service territories of the state does not advantage one territory over the other, it does not take into account the economic realities of the total cost curves of ESPs. Just as UDC total costs decrease along a stepped total cost curve, due to bulkiness, ESP costs of servicing direct access kW hours operate in an inverse bulky manner. Thus, the first block of kW hours served by an ESP comes at a higher cost per unit until efficiencies of scale begin to develop. So, while the UDCs are seeing negligible total cost impacts of the loss of customers, the ESPs are incurring large total cost impacts when those customers switch to direct access. The first few ESP customers cost the ESP more than later customers will. Conversely, the first group of customers lost by the UDCs to direct access costs them less to lose than later departing customers. This high cost of ESP direct access entry provides competitive advantages to the UDCs. In a more mature direct access market, ESP costs to service and UDC avoided costs of service will intersect on a marginal cost curve. Perhaps at that time UDC competitive advantages may be nullified and a uniform rate might be more economically desirable. We are not yet at this point.
Under present circumstances, we should make the PX credit more reflective of each UDC's actual avoided LRMC in its service territory. This is more consistent with a LRMC approach, which may carry over into other unbundling proceedings, such as revenue cycle services. In moving to a LRMC approach to determination of the PX credit, it was our intent to eliminate market power advantages of the UDCs and accurately reflect avoided costs. At this nascent point in the direct access market, we believe that high market penetration costs of ESPs justify a utility specific approach. Additionally, UDC specific PX credits match each UDC's total cost curve more precisely for purposes of ongoing proceedings to consider not only the future ramifications of the bulkiness of output blocks for purposes of the PX credit, but also for unbundling of other UDC services. We will look at the PX credit issue again for 2003 and will reassess the PX credit based on LRMC studies that take into account the bulkiness of the output blocks on a UDC by UDC basis. Therefore, we adopt PX credits of 0.014 cents/kWh for SDG&E, 0.036 cents/kWh for PG&E and 0.030 cents/kWh for Edison.
ORA needed to recommend a proxy for PG&E's procurement rate, and we must consider this question before making a final determination of the appropriate credit. Because PG&E and Edison operate in the same statewide
included these costs in ARM's estimates. It is possible that incremental 376 costs are improperly included in ARM's estimate.
PG&E notes that its 1999 GRC decision adopted a negative revenue requirement for working cash, implying this cost is not included in rates because it is negative. Working cash is composed of two major components: operational working cash requirements less amounts not supplied by investors and funds needed to pay expenses in advance of collecting revenues (the lag component). The net effect of these two components as adopted in D.00-02-046 is a negative revenue requirement. The lag component of the adopted working cash revenue requirement, which is what is reflected in ARM's PX credit calculation, is positive. ARM's estimate of working cash due to lag time is actually less than what was adopted in the GRC. Therefore it is appropriate to include working cash in the credit.
There being significant questions based on PG&E's responses to modify ARM's analysis, we will not adopt ARM's figures for the procurement adder to the PX credit. Instead, we will continue our conservative approach and adopt ORA's credit recommendation (as modified) as a proxy for an adjustment to ARM's recommendation.
In summary, we believe the appropriate credit is defined by ORA's figures for each utility, as modified in our discussion above. The credit level will be 0.014 cents per kWh for SDG&E, 0.036 cents/kWh for PG&E, and 0.030 cents/kWh for Edison.
One final note: ORA's recommendations were determined by dividing the utility's procurement costs by the usage of bundled customers, on the theory that procurement costs are only incurred on behalf of bundled customers (including future bundled customers who the utility is obligated to serve as
default provider). We agree in concept, and our adopted credit incorporates this idea. However, we realize that a problem may occur down the line. If more and more customers move to direct access, the relative usage of bundled customers will decrease. If the credit is determined by dividing LRMC of procurement by an ever-shrinking usage total, the credit will increase and the burden on bundled customers will also increase. In the extreme, the last bundled customer will pay all procurement costs (of course, bundled procurement costs should be minimal at this theoretical point, since the long-run variability of all costs would have played itself out).
At this time, we will adopt credits based on bundled usage figures. However, in future reviews of procurement credits, we intend to reconsider the appropriateness of this part of the methodology and the impact of bulkiness on such methodology.
RMR generation is generation the Independent System Operator (ISO) determines is required to maintain a reliable transmission system, including generation to meet reliability criteria, load demand in constrained areas, and voltage and security support needs. Before the Commission initiated restructuring of the California electric industry with D.95-12-063, energy users paid the costs of those same transmission support functions. The vertically integrated utilities used generation resources as a substitute for certain
In this RAP, SDG&E has calculated the LRMC of providing commodity procurement service to be .003¢/kWh. SDG&E asserts that because it had already ended its rate freeze it is necessary to split the .003¢/kWh between a PX credit of .001¢/kWh (to benefit direct access customers only) and a PX charge of .002¢/kWh (to be charged to bundled commodity service customers only). The result is that direct access customers will benefit by the .003¢/kWh differential compared to the amount paid by bundled customers.
Because SDG&E is proposing that a PX charge of .002 ¢/kWh be included in the existing electric energy change on its customer bills, it contends that a slight and minor rate increase could result. Normally, a formal application to increase rates is required by Commission rules. However, the Commission's GO 96-A, in Section VI, allows a utility to avoid a formal application to increase rates where the rate increase is minor in nature. Specifically, the rules states in pertinent part: "In cases where the proposed increases are minor in nature, the Commission may accept a showing in the advice letter provided justification is fully set forth therein, without the necessity of a formal application." Therefore, SDG&E moves the Commission, should it agree with SDG&E's proposal for a PX charge, to allow SDG&E to implement the PX charge by filing an advice letter pursuant to GO 96-A.
TURN objects to granting SDG&E's motion on the ground that it seeks relief beyond the scope of this RAP.
We will deny the motion. GO 96-A provides for review by our Energy Division. As we understand SDG&E's motion, if we were to grant it, the Energy Division review would be omitted. Our order in this proceeding authorizes an advice letter filing to implement the 0.014 cents/kWh credit for SDG&E. Should SDG&E require further relief by way of a minor increase in rates it may file under GO 96-A for review by the Energy Division.
VIII. Comments on Proposed Decision and Alternate
Comments were submitted by The Center for Energy Efficiency & Ren, Alliance for Retail Markets, San Diego Gas & Electric Company, California Department of General Services, Pacific Gas and Electric Company, Southern California Edison, ORA/Ramos/PUC, Alget Consumer Alliance, San Francisco Bay Area Rapid Transit, Coalition of California Utility Employee, California Farm Bureau Federation, The Utility Reform Network. The alternate proposed decision of Commissioner Neeper was modified as a result of the comments by lowering the PX procurement credit from 34 cents/Mwh to 32 cents/Mwh. Other non-substantive clarifications were made as a result of comments as well.
A. Power Exchange Credit Issues
1. D.99-06-058 states that, under the restructured electricity market in California, customers may subscribe to "bundled service" from the utility or "direct access" service from a competitive energy provider. Customers who purchase bundled service from the utility pay a PX charge to cover the utility's power supply costs, while customers who elect direct access service receive a credit on their bills called the "PX credit" that offsets the energy costs included in the bundled rate.
2. D.99-06-058 adopted refinements to the method of calculating the PX credit, and concluded that there was not an adequate record to adopt changes to its composition at that time, and ordered its composition to be reviewed in the current RAP.
32. ARM proposed procurements adders of 0.065 cents per kWh for SDG&E, 0.067 per kWh for Edison, and 0.059 cents/kWh for PG&E based on its studies.
33. If all appropriate procurement costs are assigned to serving bundled service customers, the total procurement costs should be divided by bundled service sales. After adjustments, the resulting procurement rates are 0.034 cents/kWh for PG&E, 0.028 cents/kWh for Edison, and 0.013 cents/kWh for SDG&E.
34. The ORA methodologies were criticized by the utilities and ARM. Certain of these criticisms are valid and require upward adjustments to ORA's credit recommendations to take into account costs identified by ARM but not included in ORA's figures.
35. The utilities as a provider of competitive services should be required to interact with other parts of the utility through the same mechanisms as other ESPs, including comparable access to information, thus ensuring a "level playing field" and providing a realistic test of whether substantial costs are required to serve bundled-service customers.
36. The Commission's policy determinations in other proceedings support only allocating procurement costs to the PX rate paid by bundled service customers, and not to rates that direct access customers would not be charged, since they have chosen to forgo the utilities' procurement services by selecting other ESPs.
37. D.99-06-058 (the 1998 RAP Decision) required that the LRMC of the utilities' energy procurement services be calculated so that it could be added to the PX credit.
38. LRMC is the change in cost associated with a small change in output, over a long enough time that all factors of production that are capable of varying can be changed.
10. Budget data for PG&E submitted in this proceeding should not be used to calculate the PX credit.
11. ARM's recommended PX costs for PG&E should be adjusted to take into account improper inclusions. ORA's recommended PX adder for PG&E is a reasonable proxy for an adjusted ARM figure.
12. This proceeding cannot be considered to have said the last word on the establishment of a rate component for commodity procurement, since issues under consideration in other proceedings will not have been decided in time for inclusion in the rates being set in this proceeding.
13. The Commission should allow parties to the next RAP proceeding to propose adjustments to the commodity procurement rate, to reflect the outcome of the RCS/DASF proceeding.
14. The utilities as a provider of competitive services should be required to interact with other parts of the utility through the same mechanisms as other ESPs, including comparable access to information, thus ensuring a "level playing field" and providing a realistic test of whether substantial costs are required to serve bundled-service customers.
15. The Commission's policy determinations in other proceedings support only allocating procurement costs to the PX rate paid by bundled service customers, and not to rates that direct access customers would not be charged, since they have chosen to forgo the utilities' procurement services by selecting other ESPs.
16. The difficult process of determining these amounts should be simplified in future proceedings by establishing a standard definition of pertinent functions,
which the utilities should then be expected to use when recording their procurement-related costs in order to enable future audits to verify that all pertinent costs have been recorded in a transparent manner.
17. The utility-specific procurement cost adder to the PX credit that should be adopted and implemented for SDG&E is 0.014 cents/kWh, for PG&E is 0.036 cents/kWh, and for Edison is 0.030 cents/kWh.
18. This Commission cannot legally order Edison to make a Federal Power Act Section 205 filing at FERC under Mass. Dept. of Pub. Util. v. U.S., 729 F.2d 886 (1st Cir. 1984). However, this Commission has jurisdiction to decide how much of Edison's RMR costs Edison may recover from its distribution customers.
19. The filed rate doctrine does not apply in this case because Edison elected to file for a mechanism to recover if its RMR costs at this Commission rather than at FERC.
20. Aglet's recommendation that the Commission allocate a percentage of total RMR costs incurred by Edison since April 1998 to wholesale customers and thereby disallow a portion of the RMR costs already paid to the ISO is denied.
21. Edison is put on notice that it will not be able to prospectively recover 100% of its RMR costs in its TRA.
22. SDG&E's request to segment the PX credit between a credit and a charge is denied.
23. SDG&E's request to increase rates is denied.
24. The stipulations set forth in Appendices B and C are adopted.
25. The uncontested issues described in the Findings of Fact are reasonable and are adopted.
26. The PX credit issue is severed from the RAP.
27. The utility distribution companies shall file their next PX credit adjustment proceeding September 2003.
IT IS ORDERED that:
1. The Power Exchange credit adder to be credited to the electricity bill of each direct access customer in San Diego Gas & Electric Company's (SDG&E) service territory is 0.014 cents per kilowatt-hour (cents/kWh), in Pacific Gas & Electric Company's (PG&E) service territory is 0.036 cents/kWh, and in Southern California Edison Company's (Edison) service territory is 0.030 cents/kWh. This adder shall be credited in addition to the credit that offsets the wholesale procurement of energy for bundled customers.
2. Within 15 days after the effective date of this order the utility distribution companies shall file tariffs implementing Ordering Paragraph 1.
3. In Edison's next RAP application, Edison shall delineate the efforts it has undertaken at the Federal Energy Regulatory Commission to recover a fair share of Reliability Must-Run Costs from its wholesale customers.
4. SDG&E, PG&E, and Edison shall file their next Revenue Adjustment Proceeding (RAP) on September 1, 2000.
5. The PX credit issue is severed from the RAP.
6. SDG&E, PG&E, and Edison shall file their next PX credit application in September 2003.
7. Application (A.) 99-08-022, A.99-08-023, and A.99-08-026 are closed.
This order is effective today.
Dated , at San Francisco, California.
