XXI. Comments to the Proposed Decision
The Proposed Decision of the ALJ was issued in accordance with Section 311(d) and Rule 77.1 of the Rules of Practice and Procedure. Comments and reply comments were filed by many parties.20 Comments merely repeating arguments made in briefs will not be considered.
1. As a result of our review of the Proposed Decision during the comment period we have determined that our approval of the SoCalGas Joint Recommendation must be modified. Our concern with the JR is not with the substantive recommendations on issues. Rather, it is with the implications of the following introductory language of the JR.
"Unless expressly noted otherwise, it is the intention of the Parties that this Joint Recommendation and sponsoring testimony applies for the purposes of this BCAP proceeding only and extends for the full three year BCAP period. It is the intention of the Parties that the Commission should not apply to SoCalGas before December 31, 2002 other cost allocation methodologies, throughput measures, or revenue risk treatment which are inconsistent with the agreement reached in the Joint Recommendation. This provision excludes the potential future unbundling of core interstate pipeline capacity. It is further the intention of the Parties if the core's ten percent ITCS responsibility is reduced in another proceeding, such a modification should not be implemented prior to January 1, 2002. The Parties agree that nothing in this Joint Recommendation and sponsoring testimony may be used as precedent or an admission in any other proceeding or forum; provided that the Parties may introduce the exhibit and sponsoring testimony in a proceeding for the sole purpose of implementing the agreed to resolution of issues as settled in this exhibit." (Emphasis added.)
We cannot approve the underlined language. We cannot permit ORA to be bound from presenting testimony and taking positions in other Commission proceedings which might affect SoCalGas prior to December 31, 2002, in a way inconsistent with the JR. Nor should we bind ourselves in the same way. We are particularly concerned with the possible affect of the JR on our Gas Industry Restructuring investigation I.99-07-003. The JR should not be cause to delay any portion of that OII. Other proceedings involving SoCalGas may arise in the coming years which could impinge on the JR. We do not want to foreclose either ORA's or our ability to act. Further, the Parties should not be foreclosed from assisting the Commission in developing a complete record on other SoCalGas matters.
A recommendation such as the JR has no precedential effect (cf. Rule 51.8). Issues settled in the JR do not foreclose consideration in other proceedings. Therefore, we adopt the JR but we specifically disapprove of the language underlined above.
2. Pursuant to an agreement between SoCalGas, ORA, and TURN the G-10 and G-20 core commercial and industrial classes have been combined. This has caused a slight revision to the Appendix D Table 1, 2, 3, and 18 in regard to core commercial and industrial rates. No other rate classes are affected.
3. In regard to the RLS tariff the Proposed Decision ordered its termination by December 31, 2002. On reconsideration, we believe that a date in 2002 unnecessarily delays termination. SoCalGas needs only a reasonable opportunity to propose a substitute. In our opinion a date one year from the effective date of this order should be more than adequate.
4. SoCalGas and others believe that the discussions of NCO v. rental methodologies and the replacement cost adder are too extensive and are superfluous in a decision that adopts a joint recommendation on these issues. We disagree. The discussion is not to be considered precedential. It was inserted to show the controversy and the reasonableness of the settlement. We have added some language to the discussion to show more clearly the position of those opposed to ORA and TURN.
5. In regard to the DGN contract SoCalGas has correctly pointed out that the Proposed Decision treated DGN differently than other wholesale customers. To correct this and treat DGN similarly to other wholesale customers, the DGN annualized customer cost, which the Proposed Decision found to be $457,021, is reduced to $22,034.
6. TURN points out that the adopted bundled residential rates in the Proposed Decision have been miscalculated. Commodity costs should be excluded from the calculation and the per-therm value of the customer charge (15.965 cents) should be added to the Tier I volumetric rate. TURN recommends calculating the differential between the Tier I and Tier II volumetric rates (excluding gas costs) so as to maintain a fixed composite tier differential. We agree and will adopt a 5% composite differential as TURN recommends. Appendix D, Tables 2 and 3 have been modified to correct the tier differential and continue the inverted residential rate structure.
7. SoCalGas, ORA, SCGC, and others continue to recommend segmentation of the EG class at 3,000,000 therms annually. Upon review, we agree with this recommendation and the decision has been modified accordingly.
8. In regard to the Wheeler Ridge cost roll-in, SoCalGas states that to implement the roll-in its Schedule No. G-ITC-Interconnect Access Service should be modified. SoCalGas asserts that since all the costs associated with the Wheeler Ridge facilities have been rolled-in, the firm and interruptible volumetric charges, the zone rate credit, and fuel charge components of the tariff will be eliminated. The single tariff component that will be retained from Schedule No. G-ITC will be the firm access reservation charge. The reservation charge will continue to be charged to SCE and SDG&E based on their daily firm access quantity. This is consistent with the Proposed Decision requirement that these firm access contracts remain in effect and consequently these customers continue to pay for the firm access rights. As SDG&E stated in its Reply Brief (pp. 27-28), in exchange for retaining firm access rights at Wheeler Ridge it is appropriate and acceptable to continue to pay for that firm access.
SoCalGas submits the following Finding of Fact: "Schedule G-ITC should be modified to eliminate the firm and interruptible volumetric charges, the zone rate credit, and fuel charge components of the tariff. The firm access reservation charge will be sole charge component of the tariff that will be retained."
SoCalGas' analysis is correct and its proposed Finding of Fact will be adopted.
9. SoCalGas complains that the Proposed Decision fails to reflect any acknowledgement, acceptance or rejection, of testimony presented by SoCalGas stating that various conditions should be removed from its tariffs that provide cogeneration customers with the right to make service elections after UEG customers have made their elections for service. SoCalGas' reason for removing these conditions is the same as its reason for proposing to remove the CGA from the EG rate, i.e., maintaining preferences for one group (cogeneration) of the EG class customers unfairly discriminates against the other members of the EG class. SoCalGas' testimony supporting the removal of conditions from its tariffs that provide cogeneration customers with the right to make service selections after UEG customers have made their elections for service was not contested. SoCalGas submits the following Finding of Fact: "Special considerations reserved for cogeneration customers during open seasons for transmission and storage service should be removed from SoCalGas' respective storage and transmission service tariffs." SoCalGas' proposal is reasonable and will be adopted.
10. In regard to the DAP cost allocation, TURN points out that in our discussion we said "TURN's proposal is rejected." However, as TURN reminds us, the DAP cost allocation was part of the JR settlement and should not be the subject of a decision on the cost allocation's merits. We modify the decision accordingly.
11. Monsanto complains that the Proposed Decision does not explain why SDG&E's Schedule XGTS has been eliminated. It was eliminated pursuant to the SDG&E JR; but, further, the explanation is simple: The evidence shows that SDG&E incurs a revenue shortfall for every therm of gas billed under the schedule. Monsanto argues that elimination of the schedule will raise its costs of doing business. We agree.
12. In our review of the Proposed Decision we note that some positions of Long Beach were not discussed. We have briefly discussed Long Beach's position on wholesale rates in section VI.E. Its request to derive wholesale rates based on embedded costs and/or eliminate the LRMC scaler from wholesale rates would require a complete reversal of Commission policy. Long Beach's proposal has previously been rejected, and we see no reason to expand upon our prior discussion rejecting the proposal. (D.94-12-052, 58 CPUC2d 306, 337.)
Additionally, Long Beach requests that this Commission order SoCalGas to sell to Long Beach certain exclusive use facilities at the sales price of about $202,000, the book value of the facilities. SoCalGas has offered to sell the facilities for $1.9 million, which it considers to be its fair market value. Long Beach says that SoCalGas proposes to charge it $301,000 annually to recover the LRMC associated with these exclusive use facilities. (This is a reduction from the current rate of $466,000 annually.) Long Beach does not cite any authority under which we could force a sale at book value. But assuming we had the authority, Long Beach has not presented a persuasive argument for us to do so. SoCalGas has computed the rates charged Long Beach in compliance with Commission decisions. Forcing a sale to save Long Beach $1.7 million benefits no SoCalGas ratepayer, harms SoCalGas, and, we suspect, will not benefit any Long Beach ratepayer. It would be a pure windfall for Long Beach.
Long Beach complains that "since the last BCAP, Long Beach has paid for the exclusive use facilities many times over. Long Beach naturally objects to paying for those facilities over and over again." (Long Beach O.B. p. 15.) Apparently, while waiting for us to force a sale, Long Beach has paid at least $1.7 million in rates. Long Beach's position has no merit.
III. SoCalGas Joint Recommendation
1. The recommendations in the Joint Recommendation (Appendix A) are made by SoCalGas, ORA, TURN, CIG/CMA, SDG&E, Chevron, Texaco, and Vernon. These parties represent a broad spectrum of ratepayer interests.
2. The Joint Recommendation recommends certain outcomes in this proceeding related to customer marginal costs, marginal demand costs, core deaveraging, the transmission resource plan, interstate pipeline capacity, the core storage withdrawal reservation, various other storage issues, the direct assistance program, Hub revenues, core and noncore throughput forecasts, noncore revenue risk, the term of this BCAP period, and certain competitive load growth opportunities.
3. The Joint Recommendation was entered into after all direct and rebuttal testimony was reviewed by parties and substantial cross-examination occurred on the issues addressed in the Joint Recommendation.
4. The recommendations in the Joint Recommendation are the result of significant negotiation and compromise of the parties thereto on issues significantly affecting their constituents.
5. The recommendations in the Joint Recommendation, resulting from negotiation and compromise, are recommended as an integrated whole.
6. Each recommendation in the Joint Recommendation is reasonable and in the public interest.
7. The Joint Recommendation is not procedurally flawed, is not contrary to Commission policy, and does not impede transportation or storage competition.
8. The Joint Recommendation is approved, except for the following language in the JR introduction which is disapproved:
It is the intention of the Parties that the Commission should not apply to SoCalGas before December 31, 2002 other cost allocation methodologies, throughput measures, or revenue risk treatment which are inconsistent with the agreement reached in the Joint Recommendation.
9. The parties to the Joint Recommendation recommend the following, as an integrated recommendation:
a. Implement the ORA position as stated in Exhibit 32 pages 7-2 to 7-3 and adopt the NCO method with the following adjustments:
1. Adjust the RECC factor as recommended by TURN and consistent with SoCalGas' Exhibit 74 at page 23,
2. Use TURN's A&G loading factor of 26.12% as shown on TURN's Exhibit 38 page 3-2,
3. Exclude the replacement cost adder component as recommended by SoCalGas in Exhibit 74 at pages 11-15,
4. Use SoCalGas' treatment of developer contributions (CIAC) consistent with SoCalGas Exhibit 74 pages 20-21 and revised in Exhibit 111, and
5. The gas engine total transportation rate will equal SoCalGas' proposed rate ($0.20384 per therm) reflected in the Updated Base Case in Exhibit 107 with the difference allocated to remaining core customers based on equal percent of marginal costs.
b. Exclude the replacement cost adder methodology from the calculation of marginal demand costs as discussed at SoCalGas Exhibit 74 at pages 11-15.
c. Adopt TURN's forecast of medium-pressure distribution marginal investment costs of $764.02 per Mcfd of peak day demand as reflected in TURN's Exhibit 38 at pages 3-11 to 3-13.
d. Adopt TURN's A&G loading factor of 26.12% and TURN's RECC factor consistent with the treatment of customer marginal costs in items a.1 and a.2 above.
e. Adopt TURN's position to deny additional core deaveraging as evidenced in TURN's Exhibit 39 at pages 26-31.
f. Implement a transmission resource plan of $32.5 million that includes the $18 million investment for Line 6900.
g. Adopt ORA's recommendation of a 1044 MMcfd for core interstate capacity reservation as recommended at Exhibit 32 at pages 6-2 to 6-3.
h. Adopt SoCalGas' position that the core retain responsibility for a portion of the ITCS as recommended at Exhibit 11 pages P5 - P6.
i. Adopt SoCalGas' recommendation to not change the allocation of Transwestern TCR surcharges as reflected at Exhibit 72 pages 9-10.
j. Use 1935 MMcfd for core storage withdrawal reservation capacity.
k. Adopt a 50/50 balancing account treatment of unbundled storage revenues. Set the at-risk unbundled storage level at $21 million. The fully scaled marginal cost of unbundled storage would be $31 million. The difference between the fully scaled unbundled noncore storage revenue requirement and the agreed upon $21 million will be charged to the noncore storage balancing account (NSBA). In the event that the NSBA is eliminated, the difference will be recovered through some other mechanism on an equal-cents-per-therm basis. The ratepayer 50% portion will also be recorded to the NSBA. The NSBA balance will be allocated to all customers equal-cents-per-therm. The shareholder 50% share of revenue variances is excluded from the PBR sharing mechanism. Consistent with SoCalGas' proposal at Exhibit 10 pages 0-1 to 0-2, the unbundled noncore storage revenue requirement excludes the Montebello storage field. SoCalGas is given pricing flexibility for all storage products provided the reservation charge will be no higher than 120% of the ceiling reservation charge currently specified in the G-TBS tariff. There will be no changes to the balancing rules as part of the 1999 BCAP.
l. Retain the current allocation method for the direct assistance program costs as evidenced in SoCalGas' Exhibit 74 pages 24-25.
m. Retain the existing HUB revenue treatment as reflected in SoCalGas' Exhibit 77.
n. Adopt the following demand forecasts plus Rosarito demand of 24.9 MMdth.
MMdth |
Demand Forecast |
Residential |
254.7 |
G-10 |
78.8 |
G-20 |
4.7 |
Gas Engine |
1.6 |
Gas A/C |
0.1 |
Total Core |
339.9 |
Commercial Industrial |
145.7 |
Electric Generation |
294.4 |
SDG&E |
119.7 |
Long Beach |
7.8 |
Southwest Gas |
9.2 |
Vernon |
5.2 |
DGN |
3.6 |
Total Noncore |
585.5 |
Total Gas Demand |
925.4 |
o. Adopt 75%/25% (ratepayer/shareholder) balancing account for noncore revenues including existing EAD contracts and future contracts as presented at SoCalGas' Exhibit 62 pages 9-11, except (1) non-tariff contracts for service to DGN, (2) future non-tariff contracts with Sempra Energy affiliates not subject to a competitive process, and (3) Competitive Load Growth Opportunities as described in section q. below. The 75%/25% balancing account treatment will apply for throughput purposes. The shareholder 25% share is excluded from the PBR sharing mechanism.
p. Adopt ORA's proposal for a three year BCAP period from January 1, 2000 through December 31, 2002 as presented in Exhibit 31 pages 2-2 to 2-3.
q. Adopt SoCalGas' proposed treatment of Red Team and Rule 38 incentive revenues as presented in Exhibit 15 pages T-32 to T-41.
IV. Length of Periods
10. The BCAP period is the years 2000, 2001, and 2002.
11. The demand forecast for the BCAP period is 950.3 MMdth.
V. Throughput
12. The throughput set forth in the JR of 925.4 MMdth plus Rosarito throughput of 24.9 MMdth (total 950.3 MMdth) is reasonable and adopted.
VI. Long-Run Marginal Costs
13. There is no evidence to support the proposition of Long Beach that the current long run marginal cost methodology should not be used to set wholesale rates.
14. The long run marginal cost methodology used for developing Long Beach's wholesale rate is identical to the long run marginal cost methodology used to set wholesale rates for all other SoCalGas wholesale customers.
15. There is no evidence demonstrating that application of the EPMC scaler to wholesale customers is unfair.
16. There is no evidence upon which the Commission can derive embedded costs for wholesale rates.
17. There is no evidence supporting Long Beach's proposition that exclusive use facilities should be sold by SoCalGas to Long Beach at net book value.
18. Simply because exclusive use facilities have a low book value does not mean that their value is trivial.
19. The load balancing cost allocation for Long Beach as proposed by SoCalGas is reasonable and consistent with that approved by the Commission in SoCalGas' 1996 BCAP proceeding.
20. Long Beach presents no evidence justifying its proposed exemption from the existing SoCalGas load balancing cost allocation methodology.
21. Long Beach provides no evidence demonstrating why average year throughput is a fairer methodology for allocating load balancing costs to wholesale customers than SoCalGas' allocation factor.
22. Long Beach provides insufficient rationale for the Commission to order SoCalGas to enter into a joint rate arrangement with Long Beach to provide gas service to certain customers.
23. There is no evidence to support implementation of a joint rate for a customer in Long Beach.
24. It is reasonable that marketing costs be allocated equally to all five wholesale customers of SoCalGas.
VII. Transmission
25. The JR transmission resource plan of $32.5 million is reasonable and is adopted.
VIII. Electric Generation Schedule
26. On April 1, 1999, the Commission approved Resolution G-3242 authorizing SoCalGas to establish a single customer class for all electricity generators in its service territory and to eliminate the collateral discount rule.
27. Resolution G-3242 ordered elimination of the CGA at the end of the Global Settlement period (August 1, 1999) provided that if the Commission did not adopt a complete proposal to eliminate gaming by August 1, 1999 then the CGA would continue in effect until such safeguards are adopted by the Commission.
28. Resolution G-3242 instructed SoCalGas to address in its 1999 BCAP the issues necessary to prevent gaming.
29. The following exemplary tariff conditions are reasonable for the purpose of eliminating the Commission's gaming concerns and therefore will be adopted. The adoption of these exemplary tariff conditions allow for immediate elimination of the CGA. The tariff conditions are as follows:
r. Subject to paragraph d., the amount of gas to be billed at the electric generation rate for customers having both electric generation and non-electric generation end use on a single meter will be the lesser of a) total metered throughput; or b) a volume equal to the customer's recorded power production in kWh times the average heat rate for their electric generation facilities.
s. The difference between total meter throughput and the volume limitation specified herein will be charged the rate applicable to the other end use served off the meter. When required, as a condition for service under the electric generation rate, electric generation customers will provide the utility with the average heat rate for electric generation equipment as supported by documentation from the manufacturer. If not available, operating data shall be used to determine customers' average heat rate.
t. Electric generation customers receiving electric generation service will make available upon request any measurement devices required to directly or indirectly determine the kilowatt hours generated or the average heat rate for the electric generation equipment. The Utility will have the right to read, inspect and/or test all such measurement devices during normal business hours. Additional gas and/or steam metering facilities required to separately determine gas usage to which the electric generation rate(s) are applicable may be installed, owned and operated by the Utility at its expense in accordance with normal service rules; however, the Utility may, in accordance with No. 2 above utilize estimated data to determine such gas usage.
u. All electric generation customers receiving electric generation service shall be separately metered unless it can be demonstrated that a separate meter is not economically feasible.
30. Special considerations reserved for cogeneration customers during open seasons for transmission and storage service should be removed from SoCalGas' respective storage and transmission service tariffs.
31. Existing regulatory structures have created a mismatch between the pricing of gas and electricity. For gas transportation, the rates of each transporting utility are cumulated -- or "pancaked" -- so that the ultimate rate the customer sees for gas transportation increases with the number of utility service areas involved in the transport. The price the PX sets for purchases of electricity, by contrast, is uniform throughout the state (or within a zone if congestion occurs) -- a "postage stamp" rate.
32. Some California generators pay much higher rates for gas transmission service than others, solely due to their location and the mismatch in regulatory pricing regimes.
33. Competition among electric generators should be based on the efficiency of generating units and the shrewdness of their owners in the gas procurement and financial markets, not on the happenstance of which Sempra affiliate provides local gas service.
34. A Sempra-wide EG rate will benefit electric customers in the form of lower PX prices in some hours, less reliance on RMR units, and lower costs for RMR units when they are called on.
35. The San Diego load center is unusually dependent on imported electricity.
36. The electricity transmission lines that supply San Diego are often subject to physical and technical limitations that can be managed only by operating the few generating plants that are located in SDG&E's territory.
37. The owners of RMR plants receive cost-based payments that are at times higher than PX payments for the same amount of electricity.
38. The Sempra-wide EG rate will lower the cost of gas transportation for the plants served by SDG&E, and will accordingly lower the amount of the payments the ISO makes under the RMR contracts, costs that are borne by all SDG&E electric customers.
39. The Sempra-wide EG rate removes the existing disincentive new generators have against locating in SDG&E's area and existing generators have against expanding or continuing their operations in SDG&E's territory.
40. To the extent that their variable costs -- which include the cost of gas transportation -- are reduced, SDG&E generators will be able to reduce their bids to the PX.
41. Segmenting the EG class rate between those customers whose annual throughput is less than three million therms and those customers whose annual throughput is more than three million therms is reasonable and is adopted.
42. Segmenting the EG class rate between transmission level and distribution level is not reasonable and is not adopted.
43. It is appropriate that the EG class rate include low emission vehicle (NGV) program costs and RD&D program costs.
IX. ITCS and Interstate Capacity
44. A forecast of the market value of El Paso interstate pipeline capacity from August 1999 through July 2000 of 12.01 cents per MMBtu is reasonable and should be adopted.
45. The methodology SoCalGas used to derive an estimated market value of El Paso interstate pipeline capacity is reasonable.
46. Past or present San Juan basin/California border gas price differentials are unreliable as predictors of the market price of El Paso capacity.
47. SCGC's proposal to establish a market price for brokered capacity based on published indices (in lieu of actual brokered revenues) would create unreasonable risks for SoCalGas.
X. Wheeler Ridge
48. It is reasonable to eliminate the incremental pricing treatment for SoCalGas' Wheeler Ridge interconnect facilities.
49. It is reasonable to roll in the cost of SoCalGas' Wheeler Ridge facilities into SoCalGas' overall transmission rates.
50. Wheeler Ridge has provided, and continues to provide, benefits to all customers of SoCalGas.
51. The total annual revenue requirement related to the Wheeler Ridge facilities to be rolled into rates is $6.83 million per year. This increase, however, will be almost completely offset by the elimination of the zone rate credit.
52. A determination regarding the status of the long term contracts of SCE and SDG&E is not required to resolve Wheeler Ridge issues.
53. Schedule G-ITC should be modified to eliminate the firm and interruptible volumetric charges, the zone rate credit, and fuel charge components of the tariff. The firm access reservation charge will be the sole charge component of the tariff that will be retained.
XI. Storage
54. The recommendations in the JR regarding storage are reasonable and are adopted.
55. A monthly load balancing service allocation of 355 MMcfd is reasonable and is adopted.
56. TURN's recommendation that all available firm injection capacity in excess of 327 MMcfd reserved for the core (121 MMcfd) be allocated to load balancing is unsupported by the evidence.
XII. Other Operating Costs
57. A factor of 1.27% of total annual throughput is reasonable for determining SoCalGas' unaccounted for gas for the BCAP forecast period.
58. A forecast of annual losses from surface leakage, well incidents, and field blow downs of 63 MMcf for the BCAP period is reasonable and is adopted.
59. The carrying costs of gas in storage of $1,702,000 in year 2000, $1,710,000 in year 2001, and $1,710,000 in year 2002 are reasonable and are adopted.
60. Forecasts of transmission fuel at 3,865 MMcf per year, storage fuel at 2,600 MMcf per year, and miscellaneous company use fuel at 355 MMcf per year are reasonable and are adopted.
XIII. System "Windowing" Procedures
61. The issues concerning SoCalGas' operation of its receipt point "windows" are addressed thoroughly in Gas Industry Restructuring and therefore should not be addressed in this BCAP.
62. The issue of whether Hector Road should be established as a normal receipt point is to be addressed in the cost/benefit phase of Gas Industry Restructuring.
63. The issue of whether SoCalGas' receipt point "window" procedures should be tariffed is addressed in the Gas Industry Restructuring proceeding.
XIV. Hub Services
64. The issues SCGC and SCE address related to hub services are being addressed in the Gas Industry Restructuring proceeding and should be resolved in that proceeding.
65. While imbalance penalties incurred by the noncore are credited to the PGA, they are not included in the GCIM.
66. Storage imbalance penalties have no impact on SoCalGas shareholders under the GCIM earnings mechanism.
XV. RLS Tariff
67. The RLS tariff is intended to ensure that SoCalGas' remaining customers will not subsidize a customer who chooses to take service from a bypass pipeline and simply receive peaking service from SoCalGas.
68. It is reasonable to expect that Questar's Southern Trails Pipeline will commence interstate natural gas transportation service in the year 2000 and serve in the Long Beach area ARCO and its affiliate Watson Cogeneration Company, two existing SoCalGas customers.
69. It is reasonable to assume that Kern River's proposed 24-inch pipeline spur off its existing pipeline system into the Long Beach area will begin providing service to existing SoCalGas customers in November, 2001.
70. The RLS tariff was intended to be market based, not cost based. Customers always retain SoCalGas' cost based rate option.
71. There are competitive alternatives to the RLS tariff peaking service market-based rate, such as gas storage, subscribing to additional capacity, burning alternative fuels, altering maintenance schedules, and swapping products in the market.
72. Elimination of the RLS tariff would require a fundamental reevaluation of SoCalGas' volumetric rate design because there are significant differences between FERC tariff rates based upon straight-fixed variable rate design and SoCalGas' existing all-volumetric rates. All volumetric rates put SoCalGas at an inherent disadvantage in a partial bypass situation.
73. Because of the way the RLS tariff increases the otherwise applicable rate, the customers' total cost of gas service will increase as a result of its attempt to cut costs by taking lower-cost partial service from an alternative pipeline.
74. The RLS tariff is applicable to the entire load of all facilities owned by an electric generation customer in SoCalGas' territory, even when only one of the customer's facilities receives partial requirements service.
75. The RLS tariff encourages new generation to locate outside of SoCalGas' service area, and makes it more difficult for existing generation in SoCalGas' territory to compete successfully in the emerging electric markets.
76. SoCalGas forecasts a decline in electric generation throughput from 285.4 MMdth in 1999 to 226.8 MMdth in 2001, a drop of over 20%.
77. SoCalGas forecasts a drop in noncore C&I throughput from 147.0 MMdth in 1999 to 137.1 MMdth in 2001.
78. The RLS tariff increases the cost of electricity generated by plants served by SoCalGas relative to plants out of the service territory or near existing interstate pipelines.
79. PG&E does not have an RLS tariff.
80. Generation projects are being planned throughout PG&E's service territory. New generation in northern California is being sited near centers of population, where it can serve increasing loads and minimize transmission congestion.
81. In the Kern County area, generators are clustering their planned units to take some service from both interstate pipelines and PG&E.
82.
83. Nearly all of the new generation projects serving California are located outside of SoCalGas' service territory, out of state, or along the existing interstate pipeline corridor.
84. Eliminating the RLS tariff would discourage bypass by wire, to the substantial benefit of SoCalGas and its ratepayers.
85. Gas supply competition is critical to the economic survival of both existing and new electric generators (as well as large industrial customers).
86. It is not possible for "pre-bypass load factor" of the customer to exist unless the customer was a full requirements customer of SoCalGas prior to its decision to take a portion of its service from an alternative provider.
87. The current RLS tariff has no mechanism to calculate a pre-bypass load factor for a new customer, or therefore, a ceiling rate in excess of $0.00.
88. The RLS tariff does not apply to new customer load.
89. The RLS tariff should be replaced within one year after the effective date of this decision, with a peaking rate.
90. Language to this Finding is deleted.
91. Absent the RLS tariff, the different rate structures offered by SoCalGas and bypassing interstate pipelines would provide an unjustified advantage to customers that partially bypass SoCalGas.
92. SoCalGas should be permitted to propose a revision of its volumetric rate design to provide peak load service.
XVI. Regulatory Balancing Accounts
93. The changes by SoCalGas to its regulatory balancing accounts are reasonable subject to audit.
XVII. Cost Allocation
94. The sum of $396,000 TURN identifies as O&M costs associated with non-metering exclusive use facilities not included in the calculation of marginal customer costs should be included in that calculation.
95. SoCalGas' base margin should be adjusted upon initiation of the new BCAP period to add approximately $2.66 million to SoCalGas' revenue requirement to account for the costs pertaining to transmission lines 325 and 6902.
96. It is reasonable to include as an adjustment to SoCalGas' base margin the sum of $6.83 million to reflect the additional revenue requirement associated with the roll in of the Wheeler Ridge interconnection facility costs.
97. Forecasted throughput for Rosarito should be included in SoCalGas' cost allocation calculation
98. Ultramar's proposal to place a 15 million therm cap on any customer's CARE surcharge is not reasonable and is not adopted.
99. The DGN gas pipeline facilities should be included in marginal customer costs.
XVIII. Rate Design
100. It is reasonable to continue the $5 residential customer charge.
101. It is reasonable to change the summer baseline allowance for climate zones 1, 2, and 3 from 15 therms to 14 therms and the winter baseline allowance for climate zones 1, 2, and 3 from 50 therms, 65 therms, and 87 therms, respectively to 49 therms, 59 therms, and 69 therms, respectively.
102. The foregoing changes to the summer and winter baseline allowances will permit SoCalGas to comply more closely with § 739(d)(1).
103. It is reasonable to segment master meter customers using at least 100 Mth annually from the rest of the master meter class. It is reasonable to treat small master meter customers using less than 100 Mth annually as single family for the purpose of setting a customer charge.
104. For the BCAP period the master meter avoided cost credit shall include scaling and is approximately $.47 per meter per day.
105. It is reasonable to combine the G-10 and G-20 customer classes along with adopting a $10 customer charge for small commercial customers using less than 1,000 therms annually.
106. It is reasonable to segment noncore commercial/industrial customers into distribution and transmission subclasses. Each subclass will have a tariff schedule similar to the G-10 tariff. There will be a single customer charge and a declining block rate schedule.
107. It is reasonable to set the core subscription reservation charges on an all volumetric basis. An all volumetric reservation charge will provide a clear basis for a potential core subscription customer to understand the cost of the capacity associated with the services.
108. For the years 1996 and 1997, the PBOP amounts authorized to be collected by SoCalGas in rates exceeded the actual funding of PBOP liabilities by $8,713,000. It is reasonable for SoCalGas to return these PBOP overcollections to ratepayers by amortizing the balance over a one-year period.
109. SoCalGas' load balancing rules are being addressed comprehensively in Gas Industry Restructuring and are the subject of further investigation in the cost/benefit analysis phase. Therefore, it is not appropriate to resolve issues pertaining to the load balancing rules in this proceeding.
110. The revenue requirement, revenue and cost allocation, and rate changes adopted for SoCalGas are set forth in Appendix D. They are reasonable and are adopted.
XIX. Other Issues
111. The PBOP overcollection shall be amortized over one year.
112. Customer satisfaction issues should be reviewed in SoCalGas' next PBR proceeding.
113. There is no need for any type account to track the effects of QF restructuring on SoCalGas' revenue.
114. Interstate pipeline refunds should be amortized over a period of one year.
XX. SDG&E Issues
115. The Joint Recommendation of the Office of Ratepayer Advocates, San Diego Gas & Electric Company, and Utility Consumers Action Network (SDG&E JR) offers a fair and reasonable resolution of many issues, and is adopted.
116. The SDG&E JR resolves virtually all of the cost allocation issues raised by ORA and UCAN in the SDG&E BCAP.
117. The SDG&E JR's recommendation to extend this BCAP period from two years to three years (January 1, 2000 through December 31, 2002) is reasonable.
118. SDG&E's retail throughput forecast of 718 million therms is reasonable.
119. The SDG&E JR's proposed UEG throughput of 480 million therms is reasonable.
120. The SDG&E JR's cogeneration throughput forecast of 188.9 million therms is reasonable.
121. The marginal costs proposed in the SDG&E JR are reasonable.
122. The SDG&E JR's proposed $31 million resource plan is reasonable.
123. The SDG&E JR's proposed $31 million resource plan only reflects the investments SDG&E identified in its testimony (Exhibit 23) as necessary to serve forecasted load over the 15-year planning horizon.
124. The transmission LRMC must be updated to reflect an additional $7.9 million in proposed international border facilities which should be combined with other SDG&E throughput.
125. The SDG&E JR's recommendation to equalize NGV rates and to expand transport-only services to all NGV customers is reasonable.
126. The SDG&E JR endorses SDG&E's proposal to narrow the tier differential between residential baseline and non-baseline rates by 10% per year, which is reasonable.
127. The SDG&E JR recommends a single tariff schedule for SDG&E's core C&I, which is reasonable.
128. The SDG&E JR recommends retaining the existing rate design for noncore C&I customers, which is reasonable.
129. The SDG&E JR's recommendation to eliminate SDG&E's experimental schedule XGTS is reasonable.
130. The SDG&E JR maintains the status quo for calculating base margin costs.
131. The SDG&E JR allocates a reasonable level of SoCalGas gas transportation costs to SDG&E customers.
132. The SDG&E JR maintains the status quo for calculating marginal cost revenue requirements.
133. The SDG&E JR maintains the status quo for allocating non-base margin costs.
134. The SDG&E JR maintains the existing methodology for calculating CARE and DAP costs for SDG&E.
135. The WMA JR between SDG&E and WMA proposes a reasonable unit discount charge under SDG&E schedules GT and GS, and is adopted.
136. No party objected to SDG&E's proposal to eliminate Schedules GPNC and G-CSTOR. This proposal is reasonable and is adopted.
137. No party objected to the SDG&E's proposal to modify the term of service under Schedule GCORE to a one-year minimum. This proposal is reasonable and is adopted.
138. The revenue requirement, revenue and cost allocation, and rate changes adopted for SDG&E are set forth in Appendix E. They are reasonable and are adopted.
1. A Sempra-wide EG rate complies with Section 454.4. It grants parity to all cogenerators.
2. A cogenerator gas allowance is not needed to comply with Section 454.4.
3. SoCalGas' current method of collecting the CPUC fee from municipal utilities does not violate Section 454.4.
4. The RLS tariff is not in violation of the antitrust laws.
5. The CGA is eliminated.
6. SoCalGas' changes in baseline allowances complies with Section 739(d)(1).
7. The RLS tariff should be replaced within one year after the effective date of this decision with a peaking rate.
8. The revenue requirement, revenue and cost allocations, and rate changes adopted for SoCalGas are reasonable, and are set forth in Appendix D.
9. The revenue requirement, revenue and cost allocations, and rate changes adopted for SDG&E are reasonable, and are set forth in Appendix E.
IT IS ORDERED that:
1. Southern California Gas Company (SoCalGas) shall file, no later than 30 days after the effective date of this order, and at least five days prior to their effective date, revised tariff schedules which implement the adopted changes shown in Appendix D. The revised tariff schedules shall comply with General Order (GO) 96-A and shall apply to service rendered on or after their effective date.
2. San Diego Gas & Electric Company (SDG&E) shall file, no later than 30 days after the effective date of this order, and at least five days prior to their effective date, revised tariff schedules which implement the adopted changes shown in Appendix E. The revised tariff schedules shall comply with GO 96-A and shall apply to service rendered on or after their effective date.
3. For customers taking service under the Electric Generator tariff, SoCalGas and SDG&E shall require a separate meter on all facilities used solely for the generation of electricity unless it can be demonstrated that it is not feasible.
4. The Cogenerator Gas Allowances and Collateral Discount Rule are eliminated.
5. SoCalGas shall implement the antigaming tariff provisions set forth in Finding of Fact 29, with the filing of its revised tariff schedules.
6. SoCalGas shall file an application, within 60 days of the effective date of this order, containing a proposed peaking rate to replace the Residual Load Service (RLS) tariff. The RLS tariff shall expire one year from the effective date of this order, or upon approval of a peaking rate, whichever is later.
7. SoCalGas and SDG&E shall jointly file an application, within 60 days after the effective date of this order, proposing a Sempra-wide tariff for EG customers using 3,000,000 therms per year or less, as a class, which caps their rate at the level which prevailed at the EG rate in effect prior to the effective date of this order. Any shortfall in revenue shall be allocated to the >3,000,000 therm class.
8. SoCalGas shall disburse its interstate pipeline refunds in conformity with the refund plan submitted with Exhibit 196.
9. The Office of Ratepayer Advocates shall audit the SoCalGas and SDG&E balancing, tracking, and memorandum accounts for the period beginning January 1, 1996.
10. These two applications are closed.
This order is effective today.
Dated April 20, 2000, at San Francisco, California.
LORETTA M. LYNCH
President
HENRY M. DUQUE
JOSIAH L. NEEPER
CARL W. WOOD
Commissioners
I will file a dissent.
/s/ RICHARD A. BILAS
Commissioner
(See Formal File for Appendices A-F)
