VI. Findings of Fact

Southwest Gas' Motion

1. Southwest Gas Corporation filed its Reply Brief late because it was in discussion with Southern California Gas Company regarding side agreements that would allow Southwest to endorse the Comprehensive Settlement.

Context of Proceeding and Decision

2. In R.98-01-011, the Commission set goals for its restructuring of the natural gas industry and compiled a record concerning different reforms that might achieve those goals.

3. In D.99-07-015, the Commission relied upon the testimony in R.98-01-011 in choosing the most promising options for further analysis as to costs and benefits prior to adoption as part of the restructuring of the natural gas industry.

4. In I.99-07-003, the Commission allowed the parties to use the promising option framework to negotiate for mutually agreeable changes in the natural gas industry.

5. After the close of the evidentiary hearing, gas prices rose markedly at the producing basins, the California border, and the PG&E citygate.

6. In contrast to previous months, only gas coming from the San Juan basin via the Baja Path was cheaper to buy at the PG&E citygate from June through September, 2000. Transportation plus border price was less expensive on all other paths from June through September.

7. During the June to September period, the deregulation of the electric industry in the San Diego area limited the authority of this Commission to protect San Diegans from extremely high prices for electricity.

The Settlements

8. Three settlements and one proposal regarding intrastate transmission unbundling were finally considered in this proceeding.

9. Each settlement addressed many of the promising options set forth, as well as the elimination of the interstate transition cost surcharge burden borne by core customers, and each was objected to by some parties.

10. After adequate notice, no party to the SoCalGas BCAP, or other pertinent SoCalGas decisions, requested a hearing on the settlements precisely because of potential alterations to those decisions. However, hearings were held.

11. The CS addressed more promising options than other settlements, but a pivotal provision is inconsistent with current Commission policy and, as a whole, it is not the settlement that is most in the public interest based on the facts and reasons set forth at pp. 33 to 48 in the opinion.

12. The Post-Interim Settlement is not the settlement that is most in the public interest based on the facts and reasons set forth at pp. 31 to 33 in the opinion.

13. The Long Beach proposal is rejected based on the facts and reasons set forth at pp. 48 to 49 in the opinion.

The Interim Settlement

14. The Interim Settlement is the settlement that is most in the public interest at this time based on the facts and reasons set forth at pp. 50 to 60 in the opinion, and those stated below.

15. The Interim Settlement filed on December 27, 1999, Appendix I to this decision, addresses many of the issues raised in the testimony in R.98-01-011 regarding the southern California gas systems and advances the Commission's goals in restructuring the natural gas industry cautiously.

16. The IS is supported by the largest coalition of customer groups of any settlement, as well as by the utilities. It provides some benefit to and balances the interests of gas suppliers, shippers, storage operators, wholesale and retail end-use customers, and regulatory representatives, as well as SoCalGas and SDG&E.

17. The IS eliminates SoCalGas' current "windowing" process, which limits the flexibility of shippers on its system to change their nominations for gas deliveries between various receipt points on SoCalGas' system. Instead, SoCalGas will post the daily physical capacity at each receipt point and allow the upstream pipeline's capacity rights system to determine which shipper's gas will flow when a receipt point is overnominated. The pre-nomination posting of capacity will give some advance notice to customers for planning purposes.

18. Wheeler Ridge capacity, in an overnomination situation, will be allocated between upstream delivery sources pro rata on the basis of the prior day's scheduled deliveries from each upstream source. This method addresses the problem posed by two pipelines feeding the receipt point.

19. The IS establishes Hector Road as a formal receipt point on SoCalGas' system for which nominations may be made. This increases the flexibility of the overall system for all customers and shippers.

20. The IS provides criteria for indicating to SoCalGas when it needs to increase its capacity to receive gas at the Wheeler Ridge receipt point.

21. That portion of Section III of the IS that allows automatic construction of an expansion of Wheeler Ridge when the criteria is met does not allow for consideration of any change in circumstances at that time. That portion of Section III of the IS that allows for automatic cost recovery in rates as of the date the expansion is in service up to $12 million in 1999 dollars, does not allow for Commission decision regarding whether rates should be rolled in or incremental.

22. The IS provides a forum for further changes in Operational Flow Order ("OFO") procedures during the term of the Settlement if the frequency of OFOs exceeds a stated threshold initially or at a later stage. The IS also requires SoCalGas to post on its GasSelect system operating information that is as extensive as that required of PG&E and that includes post-OFO data by customer class so that customers can understand why an OFO was called.

23. The IS provides for the establishment of "pools" of transportation gas on the SoCalGas system that are intended to increase the liquidity of trading of gas supplies in southern California and to provide other benefits to gas consumers and marketers in southern California.

24. The IS changes balancing rules so that cumulative imbalances will remain the property of the transportation customer, and the customer will be subject to modified imbalance charges intended to substantially deter imbalances outside the allowed 10% monthly imbalance tolerance and daily OFO tolerances. Current rules that limit the trading of these imbalances are liberalized.

25. The IS explicitly subjects SoCalGas' Gas Acquisition Department to the same balancing rules and penalties as all other shippers on the SoCalGas system, except that the current winter balancing rules still apply only to SoCalGas' Gas Acquisition Department and core aggregation transportation marketers.

26. The IS provides a detailed methodology for determining the daily imbalances of core gas suppliers including SoCalGas' gas acquisition function.

27. The IS does not require SoCalGas' Gas Acquisition Department to buy or sell, through its supply portfolio, imbalances of transportation customers outside their tolerance levels.

28. The IS provides for the unbundling of storage capacity in excess of that needed for core reliability as determined in D.00-06-040, with provisions for the retail core's payment and retention of its share of unbundled capacity and core transport agents' options to take or decline their pro rata share.

29. In D.00-04-060, the Commission approved the provisions of the Joint Recommendation, providing for ratepayers and shareholders to share the risk of storage unbundling equally.

30. The IS provides exemplary language for SoCalGas' tariffs giving unbundled storage customers the right to assign and reassign their storage contracts in a secondary market (including for terms less than the full contract terms).

31. The IS commits SoCalGas to establishing a voluntary electronic bulletin board ("EBB") for secondary trading in storage contracts on SoCalGas' system.

32. The IS provides for recovery in rates of all implementation costs actually incurred by SoCalGas to implement its provisions, in a capitalized amount not to exceed $3.5 million.

33. The provision of the IS involving a collaborative forum for stakeholders to discuss possible further restructuring changes is moot in light of the later filed Comprehensive Settlement. The provision regarding the BCAP is also moot.

34. The IS is reasonable in light of the whole record of R.98-01-011, I.99-07-015 and the officially noticed facts in this opinion, including, but not limited to, those cited in fn.10, 34 and 36, the facts reflected in the charts on pp. 39-40, and the facts regarding Georgia's problems with marketers reflected on p. 99 at fn. 63.

35. No party raised an argument that the IS is inconsistent with the law.

36. The tariffs filed with the IS are exemplary in nature and need to be finalized, including incorporating intervening tariff revisions from D.00-06-040.

37. To the extent that provisions in the IS seek to limit the Commission's authority to act in future proceedings, the provisions are inappropriate. The Commission has a duty to act as it sees fit within the ambit of its authority.

Unbundling Interstate Core Transportation Costs

38. All customers are responsible for the cost of SoCalGas' reasonable reservations of firm interstate transportation through its contracts with the El Paso and Transwestern pipelines.

39. An ECPT allocation is consistent with earlier capacity brokering decisions of the Commission.

40. Non-residential core customers have thus far been much more likely to take advantage of core aggregation programs and it is reasonable to believe that non-residential customers are more likely to take advantage of any additional savings offered by CAT marketers derived from interstate transportation unbundling.

41. The parties to the Comprehensive settlement agreed that the equal cents per therm allocation should be used only up to a 7% release of total core interstate capacity, after which the allocation should be in proportion to the percentage of each class (residential and non-residential) participating in the core aggregation program.

42. An ECPT allocation between the core customer classes is reasonable for the first 7% release of total core interstate capacity, after which it is more reasonable to allocate any additional capacity release in proportion to the percentage of each class (residential and non-residential) participating in the core aggregation program.

43. Most bundled core customers are residential customers.

44. The estimated $5.1 million that might be saved by non-residential CAT customers from unbundled core interstate transportation capacity would be largely paid for by the bundled residential core as stranded costs without a cap on their liability under the CS.

45. In order to avoid an unfair burden on bundled core customers who are the least likely to benefit from unbundling interstate transportation capacity, it is reasonable to impose a cap on their contribution to total core stranded costs of 10% of the bundled core's allocated interstate pipeline reservation costs.

46. All stranded costs will most likely end in 2005 and 2006 or at least be significantly reduced, with the end of the SoCalGas interstate transportation contracts with the Transwestern and El Paso pipelines.

47. After interstate transportation unbundling, the CAT program in PG&E's territory still did not exceed 10% of total core volume.

48. It is reasonable to assume that it is unlikely that core participation in the CAT program will exceed 10% after interstate transportation unbundling in SoCalGas' territory.

49. The rise in the price of gas at the border indicates that interstate transportation has become a more valuable commodity. The nearly 100% use of capacity recently further indicates that a 50% value for brokered capacity is a low estimate for the near future at least.

50. Given the core dollar contribution to noncore ITCS, the short remainder of the terms of the contracts, the low percentage of expected core participation in CAT programs, and the likelihood of a more than 50% value of brokered capacity, it is reasonable to require the noncore to contribute a 50% share to core ITCS through the end of the contract terms or six years, whichever is later.

51. The last detailed study of the brokerage fee was performed by SoCalGas in its 1996 BCAP, leading to the Commission-adopted brokerage fee of $.0201/Dth. There is no evidence to support raising the brokerage fee to $.024/Dth.

Eliminating Core Contribution to Noncore ITCS

52. Core customers have been contributing to Noncore ITCS since 1993.

53. Core customers have paid between $111 and $160 million, depending upon whose calculation is used, since 1993 for noncore ITCS.

54. Core customers have not received benefit from unbundling of noncore interstate transportation capacity that even approach the costs to the class.

55. By requiring the noncore to take over the remaining years of core contribution to noncore ITCS, we will be requiring the noncore to take on what we expect to be a diminishing stranded cost liability as the value of brokered capacity rises.

56. By requiring the noncore to take over the remaining years of core contribution to noncore ITCS, we will be requiring the noncore to take on at most $7.4 million per year.

57. The heavy usage of interstate capacity seen recently would decrease stranded costs and noncore responsibility for those costs.

Other Reforms

58. Other reforms to the gas industry market structure, not included in the IS, are supported by the evidence in this record, are consistent with the law and are in the public interest at this time.

59. Public Utilities Code Section 328 no longer requires a report to the Legislature before we act on gas industry restructuring that affects core customers.

60. The current core subscription option, whereby noncore customers have the advantage of core procurement services through the utilities without participating in the entire core rate structure, is unfair to core customers and restricts the market for noncore gas commodity procurement.

61. These customers will have the option to choose to become part of the core class or use an ESP or CTA for procurement purposes.

62. Keeping the revenues from the noncore customers who have become core customers in the Noncore Fixed Cost Account until throughput amounts are adjusted in the next BCAP is unfair to the core.

63. The amount of throughput involved is anticipated to be small.

64. The core aggregation program on the SoCalGas system represents about 4.3% of total core volume. The core aggregation program on the SDG&E system represents about 3.8% of total core volume. Even with unbundled intrastate transmission, core aggregation programs in the PG&E territory have not reached 10% of total core volume.

65. The 250,000 therms/year minimum threshold for persons seeking to qualify as or remain core aggregation transportation marketers and the 10% cap on the percentage of total core market share by volume that can be served by all core aggregators on the utilities' systems limits the growth of these programs, have been abandoned in PG&E territory and are not necessary in southern California either.

66. The Gas Accord set the threshold for core aggregation programs in northern California at 120,000 therms per year.

67. Consumer protection legislation like that proffered to the Legislature in 1999 is still needed.

68. Gas procurement entities and their customers have a legitimate need for information from the utilities. Given the small percentage of customers using non-utility gas procurement entities, it is reasonable to require SoCalGas and SDG&E to work with customers and/or ESPs to provide customer-specific information like consumption data in consistent formats across different contexts, consistent with consumer protection and privacy considerations.

69. It is also reasonable to require customers and/or ESPs to pay the reasonable costs of any requests for such information until such time as the percentage rises to 8% of total core volume. An application or BCAP proposal for a rate increase to fund, in conjunction with ESPs, necessary computer hardware, software, training and education efforts at that point will more closely match customer needs instead of being well in advance of such needs.

70. Utility consolidated billing for gas service providers, as provided for in Resolution G-3301, will meet the needs of those customers in core aggregation programs now and for the near future.

71. SDG&E does not currently have a tariff facilitating utility consolidated billing for gas-only procurement agents.

72. When gas service providers do consolidated billing for the utilities, the utilities avoid costs. However, in the gas industry, utilities still must send certain mandatory information to customers, as well as consumer protection materials. It is reasonable to have ESPs or CTAs already doing consolidated billing send the inserts for the utilities and provide the information currently sent on an information-only bill utility.

73. There is a potential for disputes between the utilities and alternative gas procurement providers concerning the content of utility-provided bill inserts and modification or failure to send the inserts.

74. If gas service providers doing consolidated billing also undertook to send the utility information and bill inserts, it is reasonable to peg the avoided costs until further agreement or litigation to $0.78 for each residential bill and $1.16 for each nonresidential bill on the SoCalGas system and $0.05 for each residential bill and $0.16 for each nonresidential bill on the SDG&E system, and pass these avoided costs back to the customers.

75. Because there is a continuing dispute regarding the correct value for the avoided costs of billing and uncollectibles, these billing credit values should be temporary. We need current data as well as any intervening agreement on correct values provided to us in the Market Assessment Report ordered below, or in a separate filing prior thereto.

76. Pilot programs for customer-owned meters and customer-owned meter add-ons that have been authorized for the PG&E service area will suffice to provide information on whether to extend the program in both northern and southern California.

77. The elimination of the cap and the reduction in the threshold for participation in the core aggregation program, as well as the allowance of consolidated billing by the utilities, do not substantially change the existing program and its terms and conditions for the purchase and supply of the gas commodity.

Implementation

78. The reforms herein have been delayed and need to be implemented quickly.

79. The implementation of the IS as modified and the other reforms approved herein can take place quickly because most tariff revisions and new tariffs have been drafted and circulated already.

80. Implementation of the IS and the other reforms we approve today can be detailed in one or more compliance advice letters showing tariff revisions for both SoCalGas and SDG&E. The compliance filings need to include specifics regarding compliance monitoring, cost responsibility, and enforcement measures.

81. Advice Letter No. 2895 would create a Gas Industry Restructuring Memorandum Account with subaccounts that are unnecessary, and definitions that are vague and overbroad.

82. SoCalGas needs to have a memorandum account to book costs allowed under the IS, up to $3.5 million.

83. SDG&E may need to have a memorandum account to book costs.

84. The reforms pertinent to the core aggregation programs, billing and customer information exchange can be accomplished without large expenditures while participation in the core aggregation programs remains under 10% of total core volume.

85. The costs of unbundling core interstate transportation capacity and the retail reforms will be low for the next few years and can be paid by the utilities until the next PBR or rate case.

86. As stated in Resolution G-3301, Finding No. 9, however, we will accept an application from SoCalGas for a permanent tariff for G-CBS to coincide with its next BCAP application to allow for the comprehensive review of consolidated billing and the associated cost and labor implications.

Next Steps

87. The Legislature needs to be informed of our decisions regarding the settlements and other proposed reforms.

88. We need evidence of the effect of the changes wrought in the gas industry as a result of this decision, and the effect of the more profound changes approved in PG&E's territory. A Market Assessment Report filed the Energy Division two years after the effective date of the tariff revisions ordered in this decision will elucidate the situation and point out what further evidence is needed to aid in the determination of necessary next steps. The parties in the best position to file such a report are the utilities in southern California in cooperation with PG&E.

89. Upon receipt of the Market Assessment Report, a new investigation may need to be initiated to determine whether further reforms are needed in the gas industry structure in southern California. If initiated, such an investigation will begin by requesting responses to the utilities' market assessment report and may be consolidated or otherwise linked to extant proceedings regarding the gas industry structure in northern California.

90. The reforms approved in this decision, both in the modified IS and otherwise, need to continue in place until changed by action of the Commission or its staff.