DISCUSSION
Revenue Sharing Mechanism
The Revenue Sharing Mechanism provides the method for allocating net revenues gains or losses between shareholders and ratepayers by comparing SCE's recorded Rate of Return on Equity (ROE) to the authorized ROE benchmark. The Revenue Sharing Mechanism has three levels of distributing net revenues gains or losses among shareholders and ratepayers:
1. for the first 50 basis points around the authorized ROE benchmark, shareholders receive all net revenue gains or losses;
2. from 50 to 300 basis points around the authorized ROE benchmark, gains or losses for shareholders increases linearly from 25 to 100 percent;
3. from 300 to 600 basis points around the authorized ROE benchmark, shareholders receive all gains or losses;
4. at 600 basis points from the authorized ROE benchmark, the Rate PBR Mechanism is reevaluated.
The authorized ROE benchmark for 1998 is 11.60%. In AL 1373-E-A, SCE reports a recorded ROE of 11.16% for 1998, not triggering the revenue sharing mechanism, since the reported ROE is within 50 basis points of the Revenue Sharing Mechanism benchmark. SCE calculates its recorded ROE by subtracting distribution costs (including Income Taxes, a component of Franchise Fees, Uncollectible Accounts Expense, and interest) from Distribution Revenues, and then dividing the remainder by the Recorded Distribution Common Equity1.
As shown on Appendix C, SCE reports total Distribution-Related Operating Revenue of $1,978,791,000 for 1998, which includes $105,625,000 for Other Operating Revenue. The Commission in D. 97-08-056 adopted an Unbundled Distribution Revenue Requirement of $1,667,677,000 for 1998. SCE's Distribution-Related Operating Revenue, excluding other operating revenues, is $205,489,000 over the adopted amount. SCE's reports $1,472,906,000 for their total 1998 Distribution-Related Operating Costs, and a Net Revenue of $505,885,000. Synchronized interest and preferred debt amounted to $213,899,000. SCE's Recorded PBR Common Equity for 1998 is $2,617,702,000.
Energy Division (ED) reviewed SCE's 1998 Results of Operation Report (Appendix A and C) to track and monitor SCE's distribution cost allocation, pursuant to D. 97-08-056, and changes in total Distribution-Related Operating Costs and operations from 1997. ED's findings are discussed below.
Distribution Operating Expenses:
For 1998 SCE reports an increase in Distribution Operating Expenses of approximately $105 million, from $172 million in 1997 to $277 million in 1998. According to SCE this increase reflects the inclusion of $63 million in "Internal Chargebacks"2, $14 million in Catalina/Edison Pipeline and Terminal Company (EPTC) costs, $18 million in increased storm related expenses, and $10 million for increased line clearing and miscellaneous expenses. According to SCE, the $14 million for Catalina/EPTC costs were reflected in the Unbundled Distribution Revenue Requirement authorized by the Commission in D. 97-08-056. To support the Catalina/EPTC costs, SCE provided copies of testimony and workpapers that were used in developing the Unbundled Distribution Revenue Requirement in Application (A.) 96-12-019. SCE referenced in the workpapers $1.2 million for Catalina Operating and Maintenance Expenses, and $20 million for EPTC costs. ED reviewed SCE's supporting documentation and D. 97-08-056, and confirmed that the Catalina and EPTC costs were included in the adopted total Unbundled Distribution Revenue Requirement. However, D. 97-08-056 does not explicitly specify the costs approved. Excluding the $63 million for Internal Chargebacks and $14 million for the Catalina/EPTC costs from the total amount, SCE's Distribution Operating Expenses increased by $28 million in 1998.
Customer Accounts Expenses:
SCE also reports an increase in Customer Accounts Expenses from $137 million in 1997 to $227 million in 1998, an increase of $90 million. SCE attributes this increase to the inclusion of $70 million in "Internal Chargebacks"; $9 million for Information System Expenses for implementation of billing and other customer relationship management systems; $3 million for Call Center Expenses due to increased volume and training requirements for implementation of a new information systems; and $8 million in Miscellaneous and Other Expenses. Excluding the $70 million for Internal Chargebacks, Customer Accounts Expenses increased by $20 million in 1998.
Administrative and General Expenses:
SCE reports a decrease of $127 million in Administrative and General Expenses (A&G), from $290 million in 1997 to $163 million in 1998. In response to an ED data request, SCE clarified that of this decrease, $123 million is for the Internal Chargebacks that were accounted for in Distribution Operating Expenses and Customer Accounts Expenses (a breakdown of these costs is provided in the table below). According to SCE, in 1998 SCE began recording certain A&G Expenses, including Pension and Benefits Expenses, in the General Ledger Accounts 500-599 and 905-909 for SCE's internal management reporting.
SCE states that the Internal Chargebacks consists of Pension and Benefits Expenses, Payroll Taxes, and Internal Market Mechanism (IMM) costs. SCE provided the following breakdown for its Internal Chargebacks.
Pension and Benefits |
IMM's |
Payroll Taxes |
Total | |
Distribution Exp. |
$ 28 Million |
$30 Million |
$5 Million |
$63 Million |
Customer Accounts Exp. |
$34 Million |
$31 Million |
$5 Million |
$70 Million |
|
Admin. & Gen Exp. |
($62) Million |
($61) Million |
n/a |
($123) Million |
In response to an ED data request, SCE provided an additional breakdown of its IMM costs which it included in the Intenal Chargebacks listed above:
Service Provider |
Distribution |
Customer Accounts |
Payroll |
$0.30m |
$0.10m |
Human Resources |
0.60m |
0.28m |
Claims |
3.30m |
0.00m |
Environmental Affairs |
0.40m |
0.00m |
Information Technology |
14.40m |
18.70m |
Accounts Payable |
0.03m |
0.04m |
Procurement |
2.30m |
0.32m |
Real Estate |
7.70m |
1.41m |
Accounts Receivable |
0.00m |
4.02m |
Transportation |
0.00m |
5.38m |
Other Miscellaneous |
1.0m |
0.75m |
Total |
$30.0m |
$31.0m |
According to SCE the "IMM framework" was implemented in 1998, a process of charging "joint" or "indirect" costs for internal services to internal customers based on actual customer usage.
SCE provided further documentation of its A&G costs calculations. SCE reports a total recorded A&G of $319 million by FERC accounts. Of this total A&G, SCE states that $28 million is directly and jointly assigned to generation, $6 million directly and jointly assigned to ISO, and $53 million directly and jointly assigned to Non-ISO or distribution, the remainder $226 million SCE classifies as A&G Corporate Center costs. SCE then removed $54 million from A&G Corporate Costs because these costs are recovered through other ratemaking mechanisms. Then SCE applied the multi-factor allocation to determine the portion of A&G Corporate Costs that is charged to distribution. Allocating $111 million or sixty percent to distribution. SCE then added the $53 million listed above for costs that were directly and indirectly assigned to Non-ISO or distribution.
In D. 97-08-056, the Commission disallowed $25 million of SCE's proposed fixed A&G costs associated with fossil generation by applying the multi-factor allocation method3. The Commission also adopted, in the interim, SCE's proposed Distribution Revenue Requirement which SCE interprets as approval of its proposed method of allocating A&G costs between functions by identifying them in one of three ways: direct, joint, or common4. However, D. 97-08-056, is not specific on whether the multi-factor allocation method applies to all A&G costs. ED calculated A&G costs by applying the multi-factor method, as $159 million (after removing the $54 million that SCE recovers through other ratemaking mechanisms), approximately $4 million less than SCE's reported amount for A&G costs. ED recommends approving SCE's 1998 reported A&G costs since D. 97-08-056 indirectly approves both methods. However the Commission should monitor SCE's allocation of A&G costs to distribution given that the method of deriving these costs involves other sectors of SCE's business operations.
Customer Service and Information:
SCE reports an increase of $32 million in Customer Service and Information (CS&I) costs for 1998. In 1997 SCE reported no costs for CS&I because in D. 96-09-092 the Commission rejected SCE's assignment of CS&I cost to non-generation. In response to an ED data request, SCE states that CS&I costs were later approved in D. 97-08-056. ED reviewed this decision and found that SCE had requested to allocate $23 million5 as Distribution-Related Costs for Customer Service and Marketing Costs for its large customers. In this decision the Commission agreed that some of the costs were associated with each utility's distribution operations. However, the Commission adjusted SCE's request by $7.7 million because SCE did not specify the costs that were attributable to distribution.
SCE's FERC recorded CS&I costs (Accounts 907-910) for 1998 were $49.4 million. SCE then applied the multi-factor allocation method adopted in D. 97-08-056 for non-generation taking 64.52% of the total CS&I costs to calculate the $32 million. ED recommends approval of SCE's 1998 CS&I costs since SCE's calculation methodology is consistent with D.97-08-056.
Transmission Costs:
SCE's Operating Expenses Report includes $76 million for Transmission Costs for certain 115kV and below transmission facilities that are not under the control of the ISO. This amount is $5.7 million higher from transmission costs in 1997 when SCE's PBR applied to both Transmission and Distribution (refer to Appendix C for SCE's 1997, 1998, 1999 Results of Operation comparison table). In response to an ED data request, SCE states that certain 115kV and below transmission facilities are not under ISO control and that for ratemaking purposes the related O&M expenses are considered distribution-related costs. SCE also states that the methodology used to assign the 1998 transmission costs to distribution is based on SCE's cost separation methodology employed both in its 1998 FERC rate case (Docket No. ER 97-2355-000) and adopted by the Commission in its determination of the Unbundled Distribution Revenue Requirement in D. 97-08-056. Using this cost allocation methodology SCE assigns 75.703% of its transmission expenses to distribution. Based on this allocation percentage, SCE's 1998 recorded transmission cost for these facilities increased by $23 million from 1997.
According to SCE, the cost allocation methodology for transmission O&M expenses was developed in its FERC rate case and began with the separation of the 1995 recorded transmission O&M expenses. SCE reviewed the activity in each transmission account and identified those activities and associated costs as generation, transmission (ISO), and distribution (non-ISO). Then, SCE adjusted the data to reflect additional transmission costs forecasted for the years 1996 through 1998. Additional costs that were 100% related to a specific function were directly assigned to that function. All remaining additional costs related to the three functions were allocated based on 1995 recorded transmission separation ratios. This resulted in a non-ISO percentage of 75.703.
In D. 97-08-056, the Commission adopted, in the interim, the Distribution Revenue Requirement that each utility proposed with certain adjustments, acknowledging that each utility would have the opportunity to make their case with regard to specific revenue requirement changes in PBR or rate case proceedings6. The Commission adopted a Distribution Revenue Requirement of $1.67 billion, after removing $211 million for the Transmission Revenue Requirement and $74 million in additional cost adjustments7. SCE interprets this decision as the Commission approving SCE's cost allocation methodology. However, D. 97-08-056 does not specify any costs associated with SCE's transmission facilities that are excluded from ISO control. In this decision the Commission acknowledges FERC's authority for establishing the transmission revenue requirement. The Commission also reiterates its authority for setting rates and the revenue requirement for distribution. The Commission also rejects the utilities' proposals to set distribution rates residually8. The Commission further states that establishing a distribution cost allocation which is premised entirely on the findings of FERC would be an abrogation of our authority under Section 454 and Section 367(e)(3).
ED therefore recommends approving the inclusion of these costs conditionally for purposes of this advice letter filing, given that it is unclear whether the Commission approved, as distribution related in D. 97-08-056, the kinds of transmission costs SCE has included under its Distribution PBR. In addition, SCE should demonstrate in its General Rate Case (GRC) filing for Test Year 2002 that these costs are distribution related and reasonable.
1 Recorded Distribution Common Equity is the Recorded Distribution Rate Base multiplied by the fractional share of SCE's capital structure which is Common Equity.
2 SCE states that the "Internal Chargebacks" consists of Pension and Benefits Expenses, Payroll Taxes, and Internal Market Mechanism (IMM) costs.
3 D. 97-08-056, pg. 25.
4 SCE defines direct costs are those costs that can be associated with a single business segment and are assigned to that segment. SCE defines joint costs as those costs that are associated with multiple business segments on the basis of an indirect relationship. SCE defines common costs as those costs that have no causal relationship to a single business segment or group of segments.
5 D. 97-08-056, pgs. 26, 27.
6 D. 97-08-056, pg. 16.
7 D. 97-08-056, Appendix B.
8 D. 97-08-056, pg. 16.
