XV. Assignment of Proceeding
Michael R. Peevey is the assigned Commissioner and Jeffrey P. O'Donnell is the assigned ALJ in this proceeding.
1. D.97-12-098 states: "applicants should receive such free allowances only to the extent that the revenue expected to be received from the load to be served matches the utility's investment...ratepayers will not be overpaying in those allowances for revenues that will never materialize."
2. Costs related to distribution facilities, including line extension allowances, are recovered only through distribution rates.
3. Distribution revenues are the appropriate starting point for determining net revenue.
4. Since average distribution revenue per residential customer is the average amount of revenue that can be expected to be received from the average residential customer, it is the amount available to pay for the allowance.
5. Net revenue cannot exceed the average distribution revenue per residential customer.
6. In D.94-12-026, the Commission defined net revenue as: "That portion of the total rate that supports the utility's extension costs and excludes such things as fuel costs and other energy adjustment costs that do not support the extension costs." The Commission also determined that the allowances should be "revenue-based." That is, the allowances "would be based on the expected supporting revenues from the loads to be served by the extension."
7. In D.97-12-098, the Commission determined that line extension allowances should be "revenue justified." That is, allowances should be set such that the revenue expected to be received from the load to be served "matches" the utility's investment. The Commission also decided that the allowance should be distribution-based to reflect the unbundling of utility rates.
8. In D.94-12-026 and D.97-12-098, the Commission did not precisely define what it meant by revenues that "support" line extension costs or "match" the utility's investment.
9. There is no precise definition of what net revenues should include.
10. In D.94-12-026 and D.97-12-098, the Commission established its overall policy that the allowance should be revenue justified based on distribution revenues expected to be received from the residents of new dwellings.
11. In order for the line extension allowance to be an unreasonable subsidy, the costs of the allowance must exceed its benefits.
12. The allowance is provided by residential ratepayers.
13. The record shows that the primary direct beneficiary of the allowance is the developer.
14. Only two possible ratepayer benefits of the allowance to ratepayers have been identified in the record; a positive contribution to margin, on average, due to the addition of new dwellings, and a reduction in housing prices (new dwellings and the housing market as a whole).
15. Since it is not reasonable to assume that provision of the allowance is the sole reason that a new dwelling will be built, only some portion of the contribution to margin generated by the addition of a new dwelling would be due to the allowance.
16. Nothing in the record demonstrates what the contribution to margin would be, much less how much of any positive contribution would be due to the allowance.
17. If the new dwelling is rented, the only direct benefit to the renter would be a reduction in the rent due to a reduction in the cost of the dwelling.
18. The allowance reduces the total cost to construct a dwelling.
19. Elimination of the line extension allowances would have a 0.19% effect on new housing prices ($650,000).
20. Since the record does not indicate that prices charged by developers for new dwellings are strictly cost-based, it does not indicate what benefit the owner of a new dwelling will actually receive from the allowance.
21. Since the record does not indicate that the rent charged for a new dwelling will be strictly cost-based, it does not indicate what benefit the renter of a new dwelling will actually receive from the allowance.
22. Since the record does not demonstrate that the allowance will have a material effect on the overall price of housing, the record does not indicate what benefit customers residing in existing dwellings will receive.
23. The record does not indicate whether there is a significant benefit to ratepayers due to a reduction in new and/or existing housing prices, much less what the value of any benefit would be.
24. DRA's and TURN's references to "new customers" refer to customers residing in new dwellings and/or developers.
25. Since the record is insufficient to determine what benefits ratepayers receive from the allowance, and does not address whether there are other unquantified benefits of the allowance, it is unknown whether the allowance constitutes an unreasonable ratepayer subsidy of developers or customers residing in new dwellings.
26. The Commission's current formula for calculating the line extension allowance was previously determined by the Commission to be reasonable.
27. For the Commission to revise its line extension allowance calculation formula, as recommended by DRA and TURN, it would have to determine that there is an unreasonable subsidy and that TURN's and/or DRA's recommendations would reduce or eliminate the unreasonableness of the subsidy.
28. In D.98-09-070, the Commission directed PG&E, SCE, and SDG&E to propose changes to the line extension rules that remove revenues associated with unbundled revenue cycle services from the line extension allowance calculation.
29. In D.99-12-046, the Commission removed the RCS credit from the electric line extension allowance calculation.
30. Direct access electric service is not currently available to new customers, but may be resumed in the future.
31. Since a customer residing in a new dwelling may eventually take direct access service, future revenues from the customer may be reduced by the amount of the RCS credits.
32. RCS credits are appropriate for exclusion from the net revenue calculation because they represent lost revenues due to direct access.
33. The electric net revenue calculation should reflect factors, such as rate discounts, that may impact revenues because customers residing in new dwellings may receive such discounts.
34. The use of total electric residential distribution revenues divided by the number of customers would reflect average revenue per customer including baseline usage, discounts, etc.
35. Since most new dwellings are built by developers and the customer who will live there can not be identified until the dwelling is sold, whether that customer will receive a rate discount will likely be unknown when the allowance is provided to the developer.
36. Subsequent residents of a new dwelling may or may not receive a rate discount.
37. Developers are eligible to receive from the utilities 50% of the refundable line extension costs in excess of the allowance rather than refunds based on additional services or line extensions subsequently connected to the applicant's line extension. Whether this comprises a discount to the developer depends on whether additional services and/or line extensions are subsequently connected to the applicant's line extension, which will not be known at the time the allowance is calculated.
38. For gas line extension allowances, no equivalent of the electric RCS credits is subtracted from average residential distribution revenues in the net revenue calculation.
39. TURN's recommendation to remove downstream customer costs from gas net revenues is essentially the same as its recommendation that marginal customer service costs be removed from electric net revenues instead of RCS credits, and its reasoning is essentially the same.
40. Revenue cycle services have not been unbundled for gas, no gas equivalent of the RCS credit has been established for gas utilities as a whole, and we have not required that such a credit be deducted from gas net revenues.
41. The gas appliance usages used to determine the allowance should reflect the usages in each utility's service area, rather than aggregate California usage as used by PG&E.
42. The RASS survey is implemented at the direction of the CEC to determine appliance saturation and usage for each of the participating utilities.
43. PG&E and Sempra participate in the RASS.
44. The average residential gas distribution rate is multiplied by the appliance usages to determine the net revenue.
45. Local gas transmission costs are not recovered in residential gas distribution rates.
46. Inclusion of local gas transmission revenues in the gas net revenue calculation would not be revenue justified.
47. Once a line extension has been installed, its maintenance and replacement become the utility's responsibility.
48. No party has suggested that the life of a residential dwelling is limited to the life of the line extension.
49. The overall life of line extension facilities is approximately 30 years, with the lives of some components being longer and some shorter.
50. The utility will have to replace the line extension at the end of its useful life.
51. No party has provided evidence as to how long a residential dwelling will last on average.
52. It is common knowledge that residential dwellings, although they won't last forever, can last well in excess of 60 years.
53. The purpose of depreciation is to recover the original capital cost of facilities, adjusted for any salvage and/or removal costs, over their useful lives.
54. Depreciation does not provide for replacement of the facilities at the end of their useful lives.
55. Inclusion of depreciation in the COS factor calculation does not provide for replacement in perpetuity.
56. Net revenue is intended to be those CPUC jurisdictional revenues that will be paid to the utility and can be used to pay the costs of the line extensions.
57. Since distribution rates include costs for replacements of line extension facilities during the forecast period because they are the utility's responsibility, the net revenue based on those rates includes replacements.
58. PG&E and Sempra represent that their COS factor calculations include replacements, but they do not adjust their net revenue calculations due to that fact.
59. Changes to line extension allowances are routinely done through advice letter filings, which are intended to be as non-controversial as possible.
60. The Commission's existing policy is that the IOUs are to offer uniform residential line extension allowances throughout their service territories regardless of whether a POU can provide service.
61. POUs have the ability to offer line extension allowances.
62. Prohibiting IOUs from offering line extension allowances, while the POUs can do so, would inhibit their ability to compete for new customers in those areas.
63. In D.98-06-020, the Commission indicated its support for IOU/POU competition.
64. The record does not demonstrate a need to inhibit the IOUs' ability to compete with POUs or a reason to discriminate between applicants for IOU line extensions based on whether a POU may offer service.
65. General Order 96-A, Section III.C requires utilities to provide an estimate of the annual revenue effect if a tariff schedule filed in an advice letter will result in a change in revenues.
66. In D.94-12-026, the Commission adopted a settlement that, among other things, required the utilities to periodically review factors used to determine residential line extension allowances and modify the allowance if the review results in a change of over five percent.
67. In D.98-03-039, the Commission stated "when the Commission issues a decision that impacts factors in the formula for line and service extension allowances, the utilities should apply that decision to a recalculation of the allowances without initiating or requesting a separate ratemaking or rulemaking proceeding."
68. Line extension allowance revisions have been implemented by advice letter.
69. An allowance change advice letter does not change rates.
70. Changes in the allowance may eventually result in a change in ratebase that, in turn, may contribute to a change in rates.
71. Since rates change due to a number of factors in addition to a change in rate base, it would be uncertain when an advice letter is filed what any future rate change would be.
72. The COO charge, applicable to the refundable costs, for facilities of the type the utility would normally install, in excess of the allowance is designed to recover the costs of operating and maintaining such facilities.
73. The components of the utilities' COO charges applicable to refundable costs in excess of the allowance include O&M, A&G, property taxes, and FF&U, and no party expressed disagreement with their inclusion, except for FF&U.
74. The components of the utilities' COO charges applicable to refundable costs in excess of the allowance differ as to whether utility financing is assumed, and to what extent the facilities will be replaced.
75. Line extension facilities will have to be replaced at the end of their useful lives and, since they are owned by the utility, it will have to replace them.
76. The COO charge applicable to refundable costs in excess of the allowance does not apply to the allowance.
77. Refundable costs in excess of the allowance are contributed by the applicant.
78. The utility will incur O&M, A&G, and property taxes on the line extension facilities regardless of whether they are contributed by the applicant. These costs will be recovered through rates set in the GRC. The resulting revenues will result in FF&U.
79. The COS factor includes O&M, A&G, property taxes, FF&U, replacement of the facilities, income taxes, return on investment, and depreciation.
80. COO charges applicable to special facilities vary depending on whether the facilities are utility financed or customer financed, and whether replacement is included and for how long.
81. The applicant-financed COO charge applicable to special facilities includes the costs of O&M, A&G, property taxes, FF&U.
82. The utility-financed COO charge applicable to special facilities includes the costs of O&M, A&G, property taxes, FF&U, plus income taxes, return on investment and depreciation.
83. PG&E's COO charges applicable to special facilities include replacement at the end of the facilities' useful lives.
84. SCE's COO charges applicable to special facilities include replacement in perpetuity and, in some cases, SCE offers replacement options of no replacement (the customer would pay for replacement) and replacement for 20 years after which the customer would pay for replacement.
85. Sempra's COO charges applicable to special facilities include replacement of the facilities in the first 10 years, if needed.
86. The only difference between the utilities' methodologies for calculating the COO charge applicable to special facilities is due to the time over which replacement by the utility is covered.
87. The COO charge applicable to special facilities and the COO charge applicable to refundable costs should be the same if the special facilities are applicant-financed and replacement is provided for the same period of time because both charges would be recovering the same costs.
88. The COS factor should not equal 12 times the COO charge applicable to refundable costs because the COO charge does not include utility-financing of the costs to which it applies whereas the COS factor includes utility financing of the allowance.
89. The monthly COO charge applicable to special facilities would be equal to one twelfth of the COS factor if the special facilities are utility financed and the utility pays for replacement over the same period.
90. SCE's sub-transmission costs are recovered in residential distribution rates.
91. Inclusion of revenues associated with SCE's sub-transmission costs in the net revenue calculation is consistent with the Commission's policy that the allowance should be revenue justified.
92. TURN's recommendation that the current allowances be reduced by 20%, and frozen for five years falls beyond the scope of this proceeding.
93. TURN's proposal that customers not be given an allowance for space heating or water heating unless gas will be used for both would discourage use of electric resistance space heating and water heating where gas is available.
94. There may be cases where gas is available, but use of tankless point-of-use electric water heaters or electric heat pumps for space or water heating is appropriate, and the record does not contain sufficient information to address this possibility.
95. PG&E's request that the result from these proceedings be considered incremental to its 2007 GRC, and that it be permitted to file advice letters to record approved changes to base revenues and to recover such costs through the already-established annual gas and electric true-up advice letters is beyond the scope of this proceeding.
1. Since DRA and TURN have not shown that the line extension allowance constitutes an unreasonable subsidy, that their recommended subtraction of specified costs from the net revenue calculation would reduce or eliminate the unreasonableness of the subsidy, and that their recommendations are more reasonable than the Commission's current calculation methodology, their recommendations should not be adopted.
2. DRA's and TURN's recommendation to subtract the utility's marginal customer cost from the net revenue calculation, rather than RCS credits, should not be adopted.
3. Since we do not adopt DRA's and TURN's recommendations regarding net revenues, we should not limit allowance changes to GRCs and BCAPs.
4. Electric net revenue should be based on the average distribution revenue per residential customer calculated as the total residential distribution revenue divided by the total number of residential customers.
5. Since residential rate discounts are usually paid for by other residential customers, if the cost of a discount is not included in residential rates, but recovered separately from residential customers through a surcharge, the revenue reduction due to the discount should be excluded from the electric net revenue calculation.
6. MID's proposal to calculate customer-specific discounts for customers who receive rate or line extension cost discounts should not be adopted.
7. TURN's recommendation to remove downstream customer costs from gas net revenues should not be adopted.
8. RASS should be used to determine average household gas appliance usage for each type of use.
9. The average residential gas rate should reflect factors, such as rate discounts, that may impact revenues because customers residing in new dwellings may receive such discounts.
10. The average residential gas rate should be calculated as total residential revenues divided by total residential usage.
11. Since residential rate discounts are usually paid for by other residential customers, if the cost of a discount is not included in residential rates, but recovered separately from residential customers through a surcharge, the revenue reduction due to the discount should be excluded from the average gas rate calculation.
12. PG&E's proposal to include local gas transmission revenues in the net revenue calculation should not be adopted.
13. The Commission should require that replacement be included in the calculation of the COS factor.
14. Since we do not know how long residential dwellings will last on average and they will not last forever, 60 years should be used as the period during which replacements will be performed.
15. The Commission should not adjust net revenues due to inclusion of replacement in the COS factor.
16. Since we do not adopt DRA's and TURN's recommendations for subtracting certain marginal costs from net revenues, we need not address whether adoption of their recommendations would necessitate a change in how the COS factor is calculated.
17. Data used to calculate the allowances should include data that have been previously adopted by the Commission or derived from such data, recorded data, or data adopted by other state or federal agencies.
18. The Commission should not prohibit the utilities from offering the same line extension allowances that are allowed in the rest of their service territories in areas where service is offered by POUs.
19. The Commission should not require inclusion of a revenue impact estimate in advice letter filings to revise the allowance.
20. The COO charge applicable to refundable costs in excess of the allowance calculation should include facility replacement for the same reasons the COS factor does.
21. The COO charge applicable to refundable costs in excess of the allowance should not include capital-related costs.
22. The components of the COO charge applicable to refundable costs in excess of the allowance should include O&M, A&G, property taxes, FF&U and replacement of the facilities for 60 years.
23. For the COO charge applicable to refundable costs in excess of the allowance, 60 years should be used as the period during which replacements will be performed for the same reasons as the COS factor.
24. If the special facilities are utility-financed, the COO charge should include income taxes, return on the investment, and depreciation.
25. If replacement of the special facilities is included by the utility, the COO charge should include the cost of replacements.
26. The utilities' calculation methodologies for the COO charge applicable to special facilities meet the requirements of Conclusions of Law 25 and 26, and are reasonable.
27. SCE's sub-transmission costs should not be removed from the net revenue calculation.
28. TURN's recommendation that the current allowances be reduced by 20%, and frozen for five years should not be adopted.
29. TURN's recommendation that customers not be given an allowance for space heating or water heating unless gas will be used for both should not be adopted.
30. PG&E, SCE, SDG&E, and SCG should be ordered to file advice letters to implement the above requirements including any necessary changes to their line extension allowances or their COO charges applicable to refundable costs in excess of the line extension allowances.
31. Since PG&E's request that the result from these proceedings be considered incremental to its 2007 GRC, and that it should be permitted to file advice letters to record approved changes to base revenues and to recover such costs through the already-established annual gas and electric true-up advice letters is beyond the scope of this proceeding, it need not be addressed.
32. Hearings were necessary in these proceedings.
IT IS ORDERED that:
96. Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company, and Southern California Gas Company shall file advice letters, within 120 days of the effective date of this order, to implement the refinements to their electric and gas line and service extension allowance calculations specified below, including any necessary changes to their electric and/or gas line and service extension allowances and/or their cost of ownership (COO) charges applicable to refundable costs in excess of the line and service extension allowances.
97. Electric net revenue shall be based on the average distribution revenue per residential customer calculated as the total residential distribution revenue divided by the total number of residential customers.
98. If the cost of an electric distribution rate discount is not included in residential electric distribution rates, but recovered separately from residential customers through a surcharge, the revenue reduction due to the discount shall be excluded from the calculation of average electric distribution revenue per residential customer.
99. The results of the most recent California Residential Appliance Saturation Survey, implemented at the direction of the California Energy Commission, shall be used to determine average household appliance usage for each type of gas use.
100. The average residential gas distribution rate shall be calculated as total residential gas distribution revenues divided by total residential gas usage.
101. If the cost of a gas residential distribution rate discount is not included in residential gas distribution rates, but recovered separately from residential customers through a surcharge, the revenue reduction due to the discount shall be excluded from the average gas distribution rate calculation.
102. Replacement for 60 years shall be included in the calculation of the electric and gas cost of service factors.
103. Data used to calculate the electric and gas line and service extension allowances shall include data that have been previously adopted by the Commission or derived from such data, recorded data, or data adopted by other state or federal agencies.
104. The calculation of the electric and gas COO charges applicable to refundable costs in excess of the line and service extension allowance shall include facility replacement for 60 years, and shall not include capital-related costs.
105. Application (A.) 05-09-019, A.05-10-016, and A.05-10-019 are closed.
This order is effective today.
Dated July 12, 2007, at San Francisco, California.
MICHAEL R. PEEVEY
President
DIAN M. GRUENEICH
JOHN A. BOHN
RACHELLE B. CHONG
TIMOTHY ALAN SIMON
Commissioners
ATTACHMENT A
LIST OF ACRONYMS
Acronym |
Name |
A&G |
administrative and general |
A. |
Application |
BCAPs |
Biennial Cost Allocation Proceedings |
CARE |
California Alternative Rates for Energy |
CBIA |
California Building Industry Association |
CCSF |
City and County of San Francisco |
CEC |
California Energy Commission |
COO charge |
cost of ownership charge |
COS Factor |
Cost of Service Factor |
D. |
Decision |
DOE |
United States Department of Energy |
DRA |
Division of Ratepayer Advocates |
EPMC |
Equal Percentage Marginal Cost |
FF&U |
franchise fees and uncollectibles |
GRC |
general rate case |
IOUs |
investor-owned utilities |
MID |
collectively Modesto Irrigation District and the Merced Irrigation District |
O&M |
operations and maintenance |
PG&E |
Pacific Gas and Electric Company |
POUs |
publicly-owned energy utilities |
RASS |
California Residential Appliance Saturation Survey |
RCS |
revenue cycle service |
SCE |
Southern California Edison Company |
SCG |
Southern California Gas Company |
SDG&E |
San Diego Gas & Electric Company |
Sempra |
collectively SDG&E and SCG |
TURN |
The Utility Reform Network |
(END OF ATTACHMENT A)
