1. On March 19, 1997, CIU, CLECA, CMA, DOD, ORA, PG&E, SDG&E, and Edison filed a "Joint Motion for Adoption of Retail Transmission Rate Stipulation." No party protested the motion or the stipulation.
2. In its June 5, 1997 filings before the FERC, the Commission stated its support for the proposition that the FERC should defer to the Commission’s recommendations regarding revenue allocations and rate design for unbundled retail transmission service, as proposed by the March 19 stipulation.
3. The application of differing revenue allocation and rate design to retail transmission and retail distribution rates might result in significant shifts in cost responsibility between retail customer classes, contrary to the provisions of AB 1890 which prohibit the Commission from approving cost shifts between customer classes.
4. The rate design and revenue allocation methods set forth in the March 19 stipulation appear consistent with Commission practice and policy for each utility and appear to be consistent with FERC’s open access policies.
5. The utilities propose that the Commission adopt distribution revenue requirements equal to the difference between the total nongeneration revenue requirements and the transmission revenue requirements adopted by the FERC.
6. One of the consequences of electric industry restructuring is the increased role of the FERC in setting transmission rates and revenue requirements.
7. The utilities’ proposed method for developing distribution revenue requirements would effectively require this Commission to ignore FERC findings regarding the reasonableness of utility revenue requirements proposals and to include in distribution revenue requirements costs the utilities have identified as related to transmission.
8. Establishing a distribution revenue requirement which is premised entirely on the findings of FERC would be a delegation of Commission authority to FERC.
9. If the potential for disparate ratemaking decisions of the FERC and the Commission creates risk for the utilities, it is risk already anticipated by AB 1890 and previous Commission decisions.
10. The utilities will discontinue their role in electric dispatch and system control beginning January 1, l998. Nevertheless, the utilities seek to recover revenue requirements previously authorized to conduct generation dispatch and control activities.
11. The utilities have not demonstrated that the revenue requirements for dispatch and control will be required beginning January 1, 1998.
12. The utilities’ cost of capital may change in various operations as a result of industry changes. The need for an associated review is not urgent.
13. SDG&E’s escalation method applies recently adopted PBR escalation rates.
14. Permitting the utilities to recover generation costs in the CEMA would provide a competitive advantage to the utilities in generation markets.
15. Permitting the utilities to recover generation costs in the HSCLS would provide a competitive advantage to the utilities in generation markets.
16. Some costs of generation may be fixed over the short or medium term.
17. The utilities propose to allocate all fixed A&G costs to distribution rates.
18. All generation companies will incur fixed costs.
19. All generation companies must ultimately recover all of their fixed costs in order to be viable.
20. The utilities will have opportunities to recover fixed costs following the introduction of direct access.
21. Edison proposes to include certain SONGS and Palo Verde generation costs in distribution rates.
22. Edison and SDG&E propose to include in distribution rates the costs of marketing and customer service that they have not demonstrated are attributable to distribution operations.
23. Some of the costs associated with franchise fees and uncollectibles are attributable to generation operations.
24. PG&E proposes to create a nonbypassable charge and associated balancing account for Diablo Canyon ICIP prices that exceed market prices. PG&E does not provide any analytical or policy support for its proposal.
25. The Commission has not heretofore approved of PG&E’s proposed Diablo Canyon ICIP charge.
26. Edison proposes MAM, a nonbypassable surcharge and associated balancing account for the costs and revenues associated with 39 separate accounts, including the costs associated with its fuel pipeline terminal company which are currently included in Edison’s PBR.
27. SDG&E proposes a MAM associated balancing account for the costs and revenues of several separate accounts related to generation.
28. The MAM and Diablo Canyon ICIP accounts would reduce utility risk from that anticipated by AB 1890 and previous Commission decisions.
29. Many of the costs in Edison’s proposed MAM account are unrelated to distribution operations.
30. As part of a comprehensive regulatory program, AB 1890 authorized recovery of uneconomic utility generation costs by way of the CTC which is to be eliminated no later than March 31, 2002. AB 1890 set forth exceptions to the recovery of uneconomic generation costs by way of the CTC.
31. The uneconomic generation costs included in the MAM accounts and the Diablo Canyon ICIP account are not among the exceptions listed in AB 1890 of uneconomic generation costs which are recoverable by way of the CTC.
32. PG&E proposes to replace the existing ECAC and ERAM accounts with a TRA which serves the same purpose and functions the same as an ERAM account by guaranteeing recovery of authorized revenues.
33. The Commission is considering ERAM and ECAC accounts in the Electric Tariff Streamlining workshops.
34. Edison’s revenue allocation proposal, which applies the EPMC method on the basis of total revenues, is closest to existing revenue allocation methods and avoids an embedded cost approach.
35. AB 1890 provides that residential and commercial customers receive a 10% rate discount and pay off the rate reduction bonds issued by the utilities.
36. SDG&E proposes that the rate discount be offered only to those customers on Schedule A rather than including those who subscribe to time-of-use service.
37. AB 1890 prohibits cost shifting between customer groups and requires that direct access customers pay the same CTC as utility full-service customers.
38. The utilities propose to calculate a customer’s CTC payment on the basis of the customer’s demand and set the CTC residually based on the PX price.
39. PG&E’s method of allocating public purpose program costs according to system average percentages is closest to current cost allocation methods.
40. Edison’s proposal to reflect baseline differentials only as part of the CTC does not promote cost-based rates and does not anticipate appropriate cost allocations following the transition period.
41. Edison’s proposal to impose a separate CARE surcharge on bills rather than include them in the public purpose programs surcharge is not consistent with AB 1890, which anticipates the establishment of the public purpose program surcharge to fund CARE program costs, among other things.
42. PG&E states it is not prepared to functionalize distribution and transmission rates on customer bills by January 1, 1998.
43. The utilities propose to bill time-of-use customers for the CTC on the basis of hourly loads. The practice is likely to mask price signals to customers under certain circumstances.
44. Eliminating Edison’s Domestic Seasonal Rate Adjustment mechanism will change Edison’s risk.
45. ORA proposes to require customers who switch from a tariff subject to the 10% discount to a tariff not subject to the rate reduction bond repayment to repay the original rate reduction amounts. ORA’s proposal appears potentially complex without offsetting benefits to customers as a group.
46. Merced Irrigation District proposes that customers who leave a utility system to take service from any other entity required to impose a public purpose program surcharge should pay the surcharge only to the new entity.
47. WMA’s proposal to reduce the MAR would effectively reduce rates for master-metered customers, in violation of AB 1890’s rate freeze provisions.
48. WMA’s proposal to discount rates to master-metered customers to fund direct access costs is contrary to AB 1890’s rate freeze provisions.
49. WMA’s proposal to require tariffs to specify that tenants’ bills will not be unbundled by park owners wrongfully assumes a relationship between the utility and the park tenants that does not exist and intervenes in the business relationship between park owners and their tenants.
50. Hourly distribution line loss factors are essential for minimizing system-wide costs and ensuring accurate cost allocation that avoids cost shifting.
51. Requiring the utilities to charge the 10% discount mandated by AB 1890 to the CTC will assure that customers receive the full benefits of the discount.
52. Providing PX price information on customer bills and a notice regarding the availability of competitive energy suppliers will promote customer education about energy alternatives.
53. Customers would benefit by having separately identified charges for energy, transmission, distribution, CTC, public purpose programs and nuclear decommissioning costs.
54. Not all customers are likely to find useful information regarding emission profiles for various generation resources.
55. PG&E and BART agree that PG&E should continue to bill BART conjunctively for bundled and direct access services.
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