28. Assignment of Proceeding
Geoffrey F. Brown is the Assigned Commissioner and David K. Fukutome is the assigned ALJ in this proceeding.
1. With respect to individual uncontested issues in this proceeding, unless otherwise stated in this opinion, SCE has made a prima facie just and reasonable showing.
2. SCE has substantially recovered from the financial effects of the 2000-2001 energy crisis, and it is not necessary to consider further financial recovery in resolving specific issues in this proceeding.
3. The concept of SCE's distribution infrastructure replacement program and its assertion that its workforce is aging are reasonable.
4. SCE has the burden to show that, under the circumstances of an aging distribution system and an aging workforce, its forecasts of costs are fully justified and supported.
5. SCE's nuclear related workforce is aging.
6. SCE did remove prior aging workforce costs from the recorded data prior to estimating and including test year 2006 aging workforce costs.
7. Since certain aspects of SCE's adjustment for its aging workforce are not fully explained or justified, it is reasonable to reduce the related request by $480,000.
8. SCE's request to recover the used fuel transfer project incrementally to the three-year average of historic site projects is reasonable.
9. While certain NEI activities are related to reducing operating costs or improving plant performance, there are aspects of its advocacy of nuclear power that may not be appropriate for ratepayer funding.
10. Absent a showing that details the costs and benefits associated with participation in the NEI, TURN's recommendation to restrict ratepayer funding to 50% is reasonable.
11. SCE's request for a SONGS flexible outage schedule mechanism for the post-test years is reasonable.
12. For estimating the refueling outage core costs, SCE did not provide support for three adjustments: (1) a non-labor escalation premium of $3,300,000, (2) a supplemental labor contract change of $750,000, and (3) a $3,800,000 credit due to a change in capitalization criteria. It is reasonable to exclude the non-labor escalation premium and the supplemental labor contract change for rate recovery. Since it is an accounting change only, it is reasonable to reflect the credit due to a change in capitalization criteria as proposed by SCE.
13. Due to uncertainties associated with the main generator rotor repair, it is reasonable to exclude it from the calculation of one-time activities associated with refueling outages.
14. SDG&E's methodology for calculating its SONGS related revenue requirement is reasonable.
15. SDG&E's showing on NRC DBT costs conforms to the specifications of D.04-12-015 and is reasonable.
16. SDG&E's share of DBT O&M and capital costs have exceeded the amounts initially estimated in A.02-12-028 and authorized in D.04-12-015.
17. Mohave shut down at the end of 2005.
18. Depending on the circumstances, the return to operation of Mohave may provide significant benefits to SCE's customers.
19. At this time, a temporary shutdown is the most appropriate ratemaking scenario for Mohave.
20. SCE's forecast of O&M expenses and capital related costs associated with the temporary shutdown of Mohave are reasonable.
21. The sale of Mohave sulfur credits will result in substantial revenues to SCE.
22. The future operating status of Mohave is unknown at this time, and consideration of the Coalition's Just Transition Plan is premature.
23. The amount of money at risk related to the anticipated 2008 outage at Four Corners does not justify establishing a new ratemaking mechanism for overhaul outages.
24. It is reasonable to spread the forecasted cost of the anticipated 2008 overhaul at Four Corners over three years to normalize the anticipated cost.
25. Regarding project development cost associated with proposed utility-owned generation opportunities, SCE should be subject to the same cost recovery risks as faced by independent producers.
26. SCE's proposed Project Development Division provides certain desirable support functions. It is reasonable to give SCE the opportunity to reflect such costs in rates.
27. For the purposes of this GRC, the August 13, 2005 MOU provides a reasonable basis for SCE and CPSD to address General Order 95 and 128 violation issues. It is reasonable for SCE and CPSD to continue to work out details for establishing and implementing the new maintenance program.
28. The August 29, 2005, SCE, DRA and TURN stipulation regarding the Priority 5 issue is reasonable, consistent with law and in the public interest.
29. SCE's current opportunity maintenance approach to Priority 5 maintenance is compliant with D.04-04-065.
30. It is reasonable for SCE to continue its current opportunity maintenance practice for correction of Priority 5 items until such time as the Commission authorizes a change in Priority 5 maintenance practices.
31. For Account 560.100, advanced technologies, it is reasonable to assume savings equal 50% of the costs, and to include the net cost of $2,050,000 for the test year.
32. For Account 562.100, SCE has provided sufficient information to justify its incremental aging workforce request related to five transmission system operators.
33. For Account 566.100, SCE's forecast related to training and safety relates primarily to employees hired because of increased workload and is reasonable.
34. For Account 566.300, SCE's proposed adjustment of $1,300,000 for additional office maintenance is reasonable. Due to uncertainties related to SCE's ITT support request, it is reasonable to reduce that portion of the request by $2,200,000, or 50%.
35. For Account 570.400, SCE's request of $2,682,000 for O&M associated with capital spending is the more reasonable than zero recommended by DRA.
36. For Account 570.400, SCE's request of $1,045,000 for substation life extension activities is not supported and excluded for rate recovery.
37. For Account 571.100 for poles and structures as well as Account 571.200 for insulators and conductors, it is reasonable to exclude 15% of the life extension program cost estimate to account for potential double-counting of recorded costs as well as the possible inclusion of non-recurring costs.
38. For Account 580.100, advanced technologies, it is reasonable to assume savings equal 50% of the costs, and to include the net cost of $850,000 for the test year.
39. For the remaining portion of Account 580.100, SCE's use of a budget-based forecast to estimate distribution operations supervision & operations expense of $5,172,000 is reasonable.
40. For Account 580.200, vehicle fleet expenses, it is reasonable to use an average of SCE's and DRA's proposed increases in developing the test year forecast of $7,974,000.
41. SCE's request to increase RD&D spending by 259% is not supported. DRA's proposal to use an average of the last three recorded years is reasonable.
42. SCE's proposal to continue the one-way balancing account for RD&D is unopposed and reasonable.
43. For Account 583.400, pole inspections, DRA's proposal to normalize costs over the three GRC cycles is reasonable.
44. For Account 583.400, SAM inspections, DRA's recommendation to fund twice the number of inspections over 2003 is more reasonable than SCE's unsupported request for an approximate 400% increase.
45. For Account 586.100, turn on and off service, SCE's customer growth adjustment for labor expense is more reasonable than that proposed by TURN, since TURN's adjustment sets a 2003 base level that is less than the 2002 recorded level.
46. For Account 586.100, turn on and off service, TURN's use of customer growth plus 10% to derive non-labor costs is more reasonable than SCE's use of a three-year trend of data that is possibly distorted by the 2000 - 2001 energy crisis.
47. For Account 586.400, test or inspect meters, SCE did not provide sufficient information to justify its incremental aging workforce request related to six distribution meter technicians.
48. For Account 588.300, training, it is reasonable to assume that there are funds available in either the portion of the estimate based on the 2003 recorded amount of $21,997,000 or the $5,600,000 increase in 2004, to fund necessary and appropriate activities related to construction & maintenance accountant training, training evaluation and knowledge management, and software applications.
49. For Account 588.800, historic information demonstrates that work order write-offs are not primarily driven by customer growth. A four-year average of 2001 to 2004 recorded expenses is a reasonable method for estimating this account.
50. For Account 590.980, it is reasonable to adjust the TDBU overhead activity consistent with this decision's reductions to SCE's TDBU request.
51. For Account 593.300, supply expense, it is reasonable to assume that SCE's new way of handling materials is no less efficient than the old way.
52. For Account 597.400, repair billing meters, historically, the reprogramming of TOU meters has significantly affected the total level of expenditures, and it is reasonable to adjust this account to reflect SCE's estimate that there will be no such reprogramming during this GRC cycle.
53. For Account 456.900, added facilities, a five-year average of historic data from 2000 to 2004 is a reasonable method for calculating the test year expense.
54. The agreement between SCE and TURN regarding an audit of SCE's compliance with the requirements of D.99-09-070, which adopted SCE's Gross Revenue Sharing Mechanism for revenues received from its non-tariffed products and services, is reasonable.
55. For Account 902, non-labor meter reading expenses, SCE's requested 15% increase over 2003 levels is reasonable considering increases over the 1999 to 2003 historic period.
56. For Account 903.200, non-labor credit expenses, DRA's customer growth methodology is more reasonable than SCE's use of a three-year trend that includes data, which appears to have been affected by the 2000 - 2001 energy crises.
57. For Account 903.500, non-labor billing expenses, DRA's customer growth methodology is more reasonable than SCE's use of a three-year trend that includes data, which appears to have been affected by the 2000 - 2001 energy crises.
58. For Account 903.800, non-labor call center expenses, SCE's requested 4% decrease over 2003 levels is reasonable considering the moderate increases over the 1999 to 2003 historic period.
59. It is reasonable to reflect the Postal Service Board of Governors' November 14, 2005, approval of a postage rate increase, effective January 8, 2006, in the calculation of the forecasted test year postage expense.
60. For Account 903.900, information technology application services, given our concerns with data affected by the 2000-2001 energy crisis, lack of quantification of regulatory impacts, and productivity, DRA's use of a customer growth methodology to estimate both labor and non-labor expenses is more reasonable than SCE's use of a trend of 2001 - 2003 recorded data.
61. For Account 904, uncollectible expenses, Aglet's use of an average of 2002 and 2003 recorded information to develop the uncollectible factor, before adjustments, is a reasonable methodology to reflect the constant decline in the uncollectible factor from 1999 to 2003.
62. For Account 905.900, residential services and outreach, SCE's request for $464,000 to help it more effectively provide basic customer service to residential customers is reasonable.
63. For Account 905.900, customer process based satisfaction survey, SCE has not demonstrated the need to conduct its proposed new survey, estimated to cost $431,000.
64. For Account 905.900, internet improvements, while SCE does not fully support its request, it is reasonable to include 50%, or $200,000, to recognize the value to customers of expanded website capabilities.
65. Since DA-related costs in Accounts 901, 902 and 903 are no longer tracked separately, the forecast of those DA-related costs are embedded in SCE's forecasts for all customers. Forecasting separate DA-related costs is not appropriate at this time, due to the uncertainties associated with such estimates.
66. For Account 456, direct access fees, TURN's proposal to update the DA service fees to reflect inflation from 1999 to 2006 is reasonable.
67. For Account 908, government and mid-size business services, since SCE's proposed program appears to be replacing what SCE has done in the past, it is reasonable to reduce SCE's request by 50%, or $256,000 to reflect embedded costs.
68. For Account 908, customer process based satisfaction survey, SCE has not demonstrated the need to conduct its proposed new survey, estimated to cost $432,000.
69. For Account 908, internet improvements, while SCE does not fully support its request, it is reasonable to include 50%, or $200,000, to recognize the value to customers of expanded website capabilities.
70. For Account 908, billing and payment, SCE has not provided sufficient support to include the associated program costs of $311,000 in rates.
71. Consistent with D.05-09-018, it is reasonable to continue the EB&D program with full ratepayer funding.
72. The evidence does not support a 38% growth in Energy Center expenses from recorded year 2003 to test year 2006. It is reasonable to base the test year expenses on the 2003 recorded year amount.
73. DRA's proposal to cap increases for service charges at 25% above current levels is reasonable.
74. The service guarantee program is an important and effective tool for SCE to demonstrate to its customers that it is serious about its commitments and has a positive effect in maintaining or improving SCE's current level of customer service.
75. It is reasonable for ratepayers to pay for the labor and non-labor associated with the service guarantee program and for shareholders to pay for payments to customers.
76. SCE has investigated the customer satisfaction and the injury & illness recordkeeping problems, has taken actions it believes are appropriate, and has reported its efforts to the Commission's CSPD. CPSD's investigation of the matter is ongoing.
77. It is important to properly align and assign the benefits and costs of results sharing between ratepayers and shareholders.
78. Based on the design of SCE's Results Sharing proposal, it is reasonable to require SCE to credit ratepayers for any difference between the authorized level for Results Sharing and the recorded level, for the test year and each of the post-test years.
79. Inclusion of Spot Bonuses in the Total Compensation Study would result in SCE being, at worst, within 1.9% of market.
80. Since the new system for evaluating and awarding Spot Bonuses was implemented in November 2004, while the embedded recorded data used by SCE for forecasting test year costs is for the year 2003, the appropriate level that should be funded by ratepayers in the test year has not reasonably been established.
81. On a forward looking basis, the tracking system appears to be essential in substantiating how and why spot bonuses are awarded to employees.
82. Since the Cross Training Leadership and Executive Leadership Program provide some benefit to ratepayers, assigning 50% of the costs to ratepayers and 50% to shareholders is reasonable.
83. SCE has not requested double funding of its cross training program.
84. For Account 920/921, HR client services, SCE has provided sufficient information to justify its request for funding related to expansion of it OD/OCM activities.
85. The Executive Incentive Compensation Plan provides value for both ratepayers and shareholders. Absent specific information on how executive incentive compensation is structured and calculated, it is reasonable to allocate 50% of the costs to ratepayers and 50% to shareholders.
86. The Total Compensation Study does not specify or differentiate between ratepayer and shareholder funding for either comparator company compensation or SCE compensation.
87. For forecasting the executive compensation costs in Account 920/921, other than for the Executive Incentive Compensation Plan, it is reasonable to use an average of 2002 and 2003 data, which is reflective of current executive officer levels and salaries and excludes reduced non labor costs related to the energy crisis.
88. For Account 920/921, equal opportunity, due to uncertainties as to whether costs will return to pre-energy crisis levels and, if so, how fast that will occur, the five-year average used by DRA, which results in a test year estimate of $1,352,000, and provides an increase of $262,000 over the 2003 recorded level is reasonable.
89. For Account 920/921, in house legal resources, SCE has justified the continuation of 2003 costs, related to the documents and records management software purchase and the Whiteboard filing Tracking System, into the test year. However, continuation of $459,000 in non-labor test year expenses for computer and outside consulting services is not supported by the record.
90. There is insufficient information to justify a time tracking system for SCE's in-house counsel, but there is good reason to require additional data on the costs and benefits of such a system in SCE's next GRC.
91. For Account 920/921, regulatory policy and affairs labor, the addition of nine FTEs reasonably reflects a continuation of some vacancies and a potential lessening of workload due to some proceedings reflected in 2003 recorded data closing before and during the test year. DRA's adjustment to remove labor expenses associated with the Washington, D.C. Office is not supported by the record.
92. For Account 920/921, environmental health and safety non-labor, SCE reasonably explains that most of the increase in 2003 over 2002 was related to a $456,000 reduction in the 2002 EMF budget, which was restored in 2003.
93. For Account 920/921, public affairs, while the 2004 time-tracking study used by SCE is more comprehensive than the 2003 pilot study relied on by DRA, whether it is appropriate to apply 2004 time-tracking study results to the 2003 recorded expenses to obtain the differentiation between 2003 expenses that are properly charged to ratepayers and the 2003 expenses that are properly charged to shareholders is questionable.
94. For public affairs, while it is reasonable to include the FTE positions that have been filled in 2003 and 2004, SCE has not justified five new positions proposed for 2006.
95. For Account 920/921, energy supply & management labor expense, in order to properly calculate the average salary for 2003, the total labor expense should be divided by the average number of employees for the year.
96. For Account 920/921, QF resources labor, DRA's assumption that the overall net labor cost will be the average salary in 2003 applied to the expected number of employees in 2006 is reasonable.
97. For Account 920/921, reimbursable expenses, it is reasonable to exclude costs related to eight missing expense reports.
98. SCE has agreed to perform a review of all reimbursable expense reports for each employee included in SCE's GO 77-L submittal, whose annual total reimbursable expenses are $25,000 or more for any of the years 2004, 2005 and 2006. To cover the approximate 90% of the remaining reimbursable expenses, SCE it is necessary for SCE to also conduct another statistical study for recorded 2006 reimbursable expenses, for the remaining employees whose annual reimbursable expenses are less than $25,000, similar to that performed for 2003 recorded reimbursable expenses.
99. In proposing its adjustment for recognition awards in this proceeding, DRA did not provide any information or argument that would lead us to conclude that our discussion in the last GRC on this topic should now be disregarded.
100. In this proceeding, SCE has not shown that ratepayers benefit from SCE's decisions to diversify into non-regulated activities.
101. For Account 923, HR consulting expenses, it is reasonable to reflect the cost of benchmarking studies used to demonstrate the reasonableness of total compensation.
102. For Accounts 923 and 928, law & regulatory expenses, it is reasonable to exclude recorded data affected by the energy crisis for forecasting purposes.
103. For Account 928, law & regulatory, it is reasonable to include recorded expenses related to the Gas Border Price Investigation in forecasting test year costs.
104. For Account 923, environmental health and safety non-labor expense, while SCE's proposed budgeted costs for discrete consultant activities are reasonable, SCE did not justify the continuation of 2003 recorded costs into the test year.
105. For Account 923, ES&M consultant expenses, since SCE has not justified its ES&M consultant budget request, it is reasonable to instead use the 2003 recorded amount of $2,607,000 as the test year estimate.
106. For Account 923, QF resources consultant expenses, since SCE has not supported its $224,000 incremental request, it is reasonable to use the last recorded year as the test year forecast.
107. For Account 925, workers' compensation staff, SCE reasonably supports its test year estimate of $6,319,000, which is lower than the 2003 recorded amount of $7,324,000 but higher than the approximate unadjusted 2004 recorded amount of $5,700,000.
108. For Account 925, to forecast workers' compensation reserve, it is reasonable to use an average of 2001 and 2002 recorded data, since 2003 recorded costs do not appear to be representative of test year costs and the two-year average is not materially different from the 2004 recorded amount.
109. For Account 925, environmental health and safety, corporate safety, since SCE's budget based methodology does not consider possible cost reductions either for recorded activities that may be replaced by new programs or productivity improvements that may reduce existing costs, it is reasonable to assume that $226,000 in labor expense budgeted to improve SCE's ability to track safety performance measures, if truly necessary, can be funded from that part of the unspecified budget that is based on the recorded 2003 expense level.
110. For Account 926, pension costs, it is reasonable to adopt DRA's proposed ERISA minimum funding proposal, as adjusted by SCE to reflect updated IRS information, since it is sufficiently conservative and in line with actuarial practice.
111. For Account 926, 401(k) savings plan costs, DRA indicates that it now agrees with SCE's calculations and no longer opposes SCE's forecast.
112. For Account 926 executive benefits, assuming no significant changes to the executive benefits and no changes in the number of eligible executives, it is reasonable to escalate the 2003 recorded amount of $11,157,000 to the test year level.
113. For Account 927, franchise fees, SCE's use of a weighted average for the three-year period, to develop a single franchise fee factor that, over the three-year rate case cycle, will provide recovery of anticipated franchise fees, including those related to franchise fee factor increases that will likely occur during 2006, is reasonable.
114. Utilization of MBE suppliers is highly dependent on the utilities' needs and the availability of MBE vendors to fulfill those needs.
115. SCE's previously stated goal of 22.5% for MBE suppliers was developed when utilities' were able to exclude certain services or products due to their specialized nature and lack of potential WMDVBE suppliers, and may no longer be realistic due to the Commission's elimination of exclusions in D.03-11-024.
116. SCE has achieved significant African American representation in its management through internal development and outside hiring; it has been less successful for Latinos and Asian Americans whose population is larger than that of African Americans by six times and two times, respectively.
117. While philanthropy is an important consideration for SCE/EIX, the Commission has no jurisdiction over SCE's giving practices.
118. There is no evidentiary support for linking philanthropy and executive compensation.
119. Greenlining's proposal to link executive bonuses to supplier diversity and workforce diversity was not discussed in testimony or hearings. Substantiation and evidentiary support is lacking.
120. It would be speculative to attempt to quantify any ratepayer costs associated with Greenlining's assertion that ratepayers bear the cost of excessive executive compensation, particularly when unions take such compensation into account during bargaining with top management.
121. Transparency in reporting executive compensation is crucial when determining the reasonableness such as compensation.
122. TURN's request that the balance of funds collected for cost of removal related to non-ARO assets be recognized as a regulatory liability for ratemaking purposes is reasonable.
123. SCE separately accounts for non-ARO removal costs within FERC Account 108, Accumulated Provision for Depreciation, in accordance with regulatory accounting requirements, and has disclosed these costs in the audited financial statements filed with the Securities and Exchange Commission in accordance with financial reporting requirements.
124. Inflation is the primary reason for the significant increases in historic and projected costs of removal. Variations in assumed inflation over a plant asset's life can substantially affect the cost of removal accrual over that time period.
125. By the nature of the established cost of removal methodology where SCE is paying off current removal costs, while rates are being collected to fund future costs that are much higher than current costs, the non-ARO balance, which is already over $2 billion, will continue to grow.
126. It is reasonable to take a conservative approach in adjusting net salvage ratios, rates or accruals.
127. Except for Accounts 364 and 369, it is reasonable to use DRA's recommended net salvage rates based on the 15-year historical average.
128. Using SCE's proposed net salvage rate for distribution poles included in Account 364, the company would not accumulate sufficient funds to retire the existing poles, even if the removal costs remained at recent recorded levels, unadjusted for inflation over the remaining lives of the existing poles.
129. For Account 364, it is reasonable to use SCE's proposed compromise net salvage rate of -190%.
130. For Account 369, it is reasonable to use DRA's recommendation to cap the net salvage rate at -75%.
131. There is insufficient evidence to support the adoption of TURN's net present value methodology for determining costs of removal.
132. By the PTYR mechanism adopted by D.04-07-022, SCE was authorized plant additions for 2004 and 2005 based on its proposed budgets for those years, as presented in its 2003 GRC.
133. Pursuant to D.04-07-022, SCE filed Advice Letter 1808-E that established the CAAM for 2004-2005 to track the difference between actual (recorded) and authorized total company 2004-2005 gross capital additions plus cost of removal amounts. If, by the end of 2005, SCE fully implemented its 2004-2005 capital spending budget that was adopted in D.04-07-022, no customer refunds will be required. However, if SCE's authorized capital additions are greater than its recorded capital additions over the entire two-year period, an overcollection in revenue requirement will be recorded in the CAAM and this amount will be returned to customers.
134. In projecting the test year 2006 plant balances for this GRC, it would be reasonable to consider the results of SCE's 2006 CAAM filing as it relates to both 2004 and 2005 recorded plant additions.
135. Since SCE's proposed capital project completion dates for the test year result in an equivalent 41.16% weighting percentage, which is consistent with historical weighting percentages, it is reasonable to use SCE's proposed completion dates for adopted test year projects.
136. In calculating the AFUDC rate, it is reasonable to use the amount of short-term debt available for construction, rather than the total amount of short-term debt financed by SCE, since the majority of short-term debt is used to fund balancing account under-collections and fuel inventory. The amount of short-term debt available for construction in 2004 was $43,000,000, and is a reasonable amount to include in the calculation of the AFUDC rate for this proceeding.
137. It is reasonable to reflect allowances for costs transferred from CAC to CIAC on a forecast basis.
138. SCE's proxy approach for determining the maximum amount that ratepayers could have contributed during the ICIP period for the SONGS Used Fuel Storage and Marine Mitigation projects provides an objective basis for assigning costs that have been paid for by ratepayers.
139. The Florence Dam Buttress project that was completed in 2003 was a capital project and should never have been included in the expense forecast for the test year 2003 GRC.
140. For forecasting T&D meter set costs, due to potential productivity, it is reasonable to hold the 2004 recorded cost per meter of $2,922 constant through test year 2006.
141. In light of Resolution E-3921, TURN's suggestion to remove its issues regarding the calculation of line extension allowances in general, the exclusion of sub-transmission costs in the calculation of line extension allowances, and the utilities' data collection practices regarding line extension costs and projects, is reasonable.
142. Regarding line extension allowances for existing customers, SCE is in compliance with its current tariff language.
143. SCE's OOR forecast reasonably reflects revenues associated with forecasted costs of leased meters.
144. SCE's request for funding load growth projects in 2006 when the utilization is near or at 100% is reasonable.
145. For the wood pole replacement program, it is reasonable to use the average of the number of projected pole replacements for 2006, 2007 and 2008 in developing a normalized test year expenditure.
146. SCE's plan to replace 1,857 mainline manual oil-filled switches at 300 switches per year, starting in 2006 is reasonable.
147. SCE has identified 131 mainline spring operated oil-filled switches with known problems and its plan to replace 15 per year from 2005 to 2008 is reasonable.
148. For spring operated oil filled switches, SCE has not provided a compelling reason to increase the number of replacements from 10 in 2005 to 85 in 2006.
149. It is reasonable to replace BURD switches over a six year period, at 162 switches per year, beginning in 2006.
150. For submersible fuse cabinets, it is reasonable to replace 125 cabinets per year over this GRC cycle.
151. Without more engineering data to justify SCE's plans, it is reasonable to limit the amount of underground primary cable replacement to 100 miles per year for this GRC cycle.
152. For ARs, it is reasonable to use an average of the recorded number of 2000, 2002, 2003 and 2004 replacements to forecast the number of test year replacements.
153. The use of the 2004 recorded number of capacitor bank replacements to forecast the test year level is reasonable.
154. Based on known problems, SCE has justified replacements planned for 52 vaults/manholes and 74 BURD structures from 2004 through 2008. SCE's belief that there may be other candidates beyond these amounts is insufficient to justify 22 additional test year replacements, which would more than double the test year expenditures.
155. Using an historic average is a reasonable method for forecasting the number of test year circuits to be remeditated.
156. The cost for a circuit remediation varies significantly from year to year and SCE's rough estimate of $1,000,000 per remediation appears reasonable.
157. For wood pole repairs, SCE has justified the number of poles that must be fiberglass wrapped and steel stubbed over the GRC cycle to comply with GO 95. For ratemaking, it is reasonable to normalize the number of repairs over the three years.
158. It is reasonable to reflect SCE's modified forecasted bark beetle pole replacement costs of $3,500,000 in 2005 and $0 in 2006 in place of its original forecasted costs of $7,964,000 in 2005 and $3,318,000 in 2006.
159. For subtransmission wood pole replacements and repairs, the average cost per pole dropped to $14,197 per pole in 2004 due to work in rural areas. It is reasonable to reflect some work in rural areas in developing the test year cost per pole of $16,300.
160. For circuit automation, an average of 1999, 2000 and 2002 - 2004 historical expenditures, escalated to test year dollars, is a reasonable method for forecasting test year expenditures.
161. SCE has not justified its proposed increase in the distribution circuit breaker replacement program for 2006. It is reasonable to instead base the test year estimate on SCE's 2005 estimate, which is close to the recorded 2003 amount.
162. For A-Bank transformer replacements, the authorized 10 replacements per year would result in a replacement cycle close to the nominal design life.
163. For B-Bank transformer replacements, SCE has justified replacement of 13 transformers in the test year.
164. For distribution protection and control replacement, SCE has not provided sufficient information to justify replacing equipment at 25 substations for the test year. Base on recorded information, it is reasonable to provide funding for 21 substations at an average cost of $485,000 per substation.
165. SCE's cost estimates for the A/AA control room upgrades based on industry accepted standard engineering methods are, at this time, appropriate. Since the spending pattern over the rate case cycle varies significantly, it is reasonable to normalize the expenditures by using an average of the forecasts.
166. For the substation equipment reactive replacement program, DRA's four-year average is more appropriate, since SCE has not justified adding offset costs back into the blanket in determining its four-year average.
167. SCE has justified its request for cable trench cover replacement.
168. SCE has not provided sufficient information to support its proposed number of disconnect switch replacements.
169. SCE has sufficiently explained the basis for it proposed averaging of 1999 - 2002 data to forecast Rule 20B circuit breaker replacement costs.
170. For forecasting substation tools and grid dispatch, an average of the expenditures incurred during the post energy crisis years of 2002 and 2003 is reasonable.
171. For substation spare parts, since we have adopted SCE's capital request regarding B-Bank transformer replacements, it is reasonable to include SCE's estimate of the associated spare parts.
172. For the non-operational facility blanket, SCE has not explained why the proposed projects cannot be covered by the corporate real estate budget. SCE also did not explain why no money in this non-operational facility blanket has ever been spent.
173. Since there is no opposition to the Oak Valley project, it is reasonable to include the associated $500,000 in fee simple/rights-of-ways costs in 2006.
174. Nothing has changed regarding the Commission's reasoning for excluding fuel inventory from rate base, which included the cost to ratepayers, the balancing account treatment for fuel expenses and the low risk nature of fuel inventories.
175. The Commission's decision, in D.04-07-022, to include customer deposits as a rate base deduction is not sufficient reason to reconsider the current ratemaking policies for fuel inventory.
176. To forecast the test year M&S balance, it is reasonable to use the 2004 recorded balance of $131,419,000 and increase that amount by 3.3% per year, the average annual increase from 1999 to 2004.
177. To forecast the test year customer advances for construction balance, it is reasonable to use the 2004 recorded balance of $69,555,000 and increase that amount by cost escalation to the test year.
178. It is reasonable to include the entire forecasted weighted average customer deposit balance as an offset to rate base.
179. In light of the continuing upward trend in the recorded customer deposit balances, it is reasonable to use the 2004 recorded balance of $159,650,000 to forecast the test year amount.
180. The reserve for workers' compensation claims and the reserve for injuries and damages other than workers' compensation claims represent recorded liability accruals exceeding recorded payments.
181. The evidence does not support the proposition that ratepayers have provided the funds for the workers' compensation reserve.
182. It is reasonable to exclude atypical uncollectible accounts receivable for non-claims as an offset to working cash, since this particular uncollectible amount is not funded in rates.
183. Because of our commitment to the principles of SCE's distribution capital replacement program, it is reasonable to calculate the revenue requirement for the post test year period based on the adopted summary of earnings for 2006, inflated operation and maintenance expenses, and increased capital related costs based on the addition of specific post test year plant additions to rate base.
184. Plant additions for 2006 have been fully scrutinized in this rate case. For the post test years, it is reasonable to assume a level of plant investment similar to that for the test year, with adjustments for inflation amounting to 2.5% for both 2007 and 2008.
185. DRA's request that the Commission extend the rate case cycle associated with SCE's test year request to four years is opposed by SCE and is contrary to the current rate case plan that allows major energy utilities the opportunity to file GRC applications every three years.
186. Regarding the CCIM, SDG&E's benchmarking study does not correctly reflect such factors as plant age, percentage of plant owned and acreage. Also SONGS 2&3 should be compared to costs of nuclear plant sites, not nuclear portfolios of other utilities. Possible commingling of O&M and capital costs and use of incremental plant additions rather than also considering costs of embedded plant also are concerns with the study.
187. In this GRC, there is only one issue related to SCE's forecasts for specific SONGS capital projects even though the forecasted expenditures are significantly higher than those experienced during the ICIP years.
188. The CCIM proposal to expense SONGS capital projects over one year increases the likelihood that SCE will not recover cost increases related to events, such as that of September 11, 2001, that are beyond SCE's control.
189. The CCIM proposal to reevaluate costs in the next GRC negates some of incentive for the utility to pursue cost savings and reduce costs.
190. It is reasonable to evaluate and set authorized levels of rate recovery for SONGS on a cost of service ratemaking basis.
191. The RIIM provides an incentive for SCE to perform authorized projects and activities related to distribution reliability and a means to credit money back to ratepayer if they do not do so.
192. At this time, it is reasonable to discontinue the use of a reliability incentive mechanism that is based on rewards and penalties.
193. Adoption of the RIIM is not a shift toward recorded cost ratemaking, but merely a means for SCE to meet its commitment to spend money for reliability purposes, to the extent that it is authorized.
194. SCE is not requesting additional funding for 600 additional linemen and groundmen because of the RIIM.
195. It is reasonable to assume that 600 additional linemen/groundmen can be accommodated within the revenue requirement authorized by this decision.
196. The November 2, 2005 SCE, CUE and TURN stipulation regarding the RIIM provides reasonable procedures to ensure authorized reliability -related projects and activities are undertaken and completed. The stipulation is consistent with law.
197. Although DRA proposes that reliability levels only be maintained and not improved, it has not provided any guidance as to what level of spending is necessary to do so.
198. The RIIM accomplishes the same goal as the RDAM in that it holds SCE accountable for distribution reliability related funds that it receives in rates. At this time, the RIIM is a fairer and more appropriate mechanism to address this aspect of distribution reliability.
199. Because there is a question, due to the reliability of certain SCE injury and illness data, of whether OSHA reportable injuries is an appropriate measure for developing safety incentive, it is not reasonable at this time to continue the employee safety incentive mechanism.
200. The September 8, 2005 SCE, WMA and TURN settlement provides reasonable procedures for SCE to offer bill calculation services to submetered mobile home parks. The settlement is consistent with law and unopposed.
201. It is reasonable to reflect the GRC RRMA balance in SCE's rates and the SRRMA balance in SDG&E's rates.
1. Generation O&M expenses amounting to $452,130,000, as detailed in Appendix C, should be adopted for the test year.
2. For future requests for ratepayer funding of NEI dues, SCE should provide detailed descriptions of the activities, the associated costs, and the resulting company and ratepayer benefits associated with participation in that organization.
3. Amounts authorized by D.04-12-015 for SDG&E's SONGS Security Costs Balancing Account should no longer be subject to refund.
4. SCE should establish a two-way balancing account to record Mohave costs going forward.
5. At an appropriate time, after the permanent status of Mohave is determined, SCE should file an application seeking a final determination of the reasonableness of the costs recorded to the Mohave balancing account.
6. SCE should create a new Mohave Sulfur Credit Sub-Account in its ERRA tariff.
7. The issue of the distribution of revenues accumulated in the Mohave Sulfur Credit Sub-Account should be addressed when more information on the future operating status of Mohave is known.
8. For this GRC, SCE's request of $4,950,000 in expenses to fund its proposed PDD should be excluded from rates. However, SCE should be allowed rate recovery of costs that support new generation and that are not associated with proposed projects. SCE should track such supportive project development costs in a memorandum account. Such costs can then be recovered in future rates to the extent that they are incurred, to the extent that SCE can justify their supportive nature, and to the extent that the total recorded PDD costs do not exceed SCE's forecasted amount.
9. In SCE's next GRC, PDD costs related to specific proposed projects should be excluded from the request.
10. SCE should seek cost recovery of generation related A&G expense and general plant overheads from DA customers in its ERRA proceedings.
11. Transmission O&M expenses amounting to $79,209,000, as detailed in Appendix C, should be adopted for the test year.
12. Distribution O&M expenses amounting to $365,304,000, as detailed in Appendix C, should be adopted for the test year.
13. The August 29, 2005 SCE, DRA and TURN stipulation regarding the Priority 5 issue should be approved.
14. SCE should continue its current opportunity maintenance practice for correction of Priority 5 items until such time as the Commission authorizes a change in Priority 5 maintenance practices.
15. In the next GRC, SCE should provide a detailed showing on the need and cost of the transmission life extension program (for poles and structures as well as insulators and conductors) that is include in Accounts 571.100 and 571.200. The showing should also demonstrate the incremental nature of the life extension program.
16. SCE's current one-way balancing account for RD&D should be continued.
17. Customer Accounts expenses amounting to $227,704,000 as detailed in Appendix C, should be adopted for the test year.
18. Customer Service and Information expenses amounting to $39,908,000, as detailed in Appendix C, should be adopted for the test year.
19. Administrative and General expenses amounting to $624,208,000, as detailed in Appendix C, should be adopted for the test year.
20. Until the current CPSD investigations regarding customer satisfaction and injury & illness recordkeeping problems are resolved, SCE should not use the data or information in question in determining results sharing goals and awards.
21. In its next GRC, SCE should provide detailed information on how its final results sharing goals were determined for the 2006 - 2008 period, what steps were taken to ensure the integrity of both the data and the process for making awards, and any further consequences or any required actions imposed by either SCE or the Commission, as a result of the Customer Satisfaction and Injury & Illness Recordkeeping investigations.
22. SCE should track the authorized and recorded Results Sharing costs in a Memorandum Account.
23. In its next GRC, SCE should provide a study on, or analysis of, a time-tracking system for its in-house counsel. It should include an estimated cost of performing this activity, any perceived benefits or detriments and any analysis related to the tracking system that was in place during the 1994 - 1998 timeframe.
24. In its next GRC, for the Public Affairs Department, SCE should redo the time-tracking study to reflect the areas of responsibilities requested for the test year and ensure that the results are appropriately applied to whatever methodology is used to forecast test year expenses.
25. For its next GRC, SCE should conduct another statistical study for recorded 2006 reimbursable expenses, for the employees whose annual reimbursable expenses are less than $25,000, similar to that performed for 2003 recorded reimbursable expenses.
26. SCE should establish a two-way balancing account for pension costs, beginning with the 2006-2008 forecast period.
27. $225,000 in costs for complying with affiliate transaction rules should not be charged to ratepayers.
28. Changes to the Commission's specific goals for supplier diversity should be considered in the context of modifications to GO 156, on a generic basis, so that the views of all potentially affected parties can be considered.
29. As part of its next GRC filing, SCE should provide information on its workforce diversity achievements, similar to that provided by Greenlining in Exhibit 505.
30. For purposes of the General Order 77-L report, SCE should follow the PG&E model for reporting executive compensation.
31. In its next GRC, SCE should provide full transparent and understandable information on the present and future market value of the retirement severance benefits of its top executives.
32. Depreciation and amortization expense amounting to $793,387,000 as detailed in Appendix C, should be adopted for the test year.
33. In its next GRC, SCE should, as part of its account by account analysis for depreciation, analyze the effects of past inflation on its proposed cost of removal rates and justify the implicit inflation rates reflected in its proposed rates.
34. SCE should, as part of its account-by-account analysis for depreciation, provide analysis which quantifies potential accrual deficiencies for the future removal costs of existing assets. SCE should provide an analysis of what is causing any likely deficiencies.
35. SCE should establish a memorandum account to track the revenue requirement associated with its forecasted and recorded 2004/2005 plant additions. When plant additions are evaluated for the CAAM:
a. If SCE records plant additions at or in excess of $2,570,000,000 for the period 2004 - 2005, no further action is necessary.
b. If SCE records plant additions that are lower than $2,570,000,000 for the period 2004 - 2005, SCE should credit ratepayers with the excess revenue requirement collected through this decision, that is the difference between the revenue requirement associated with the 2004/2005 plant additions forecasted in this GRC and the revenue requirement associated with the recorded 2004/2005 plant additions. The credit should be calculated from the effective date of this decision.
36. The Florence Dam Buttress project should never have been included in the 2003 GRC expense forecast.
37. Before the costs for the Florence Dam Buttress project are included in future rates, SCE must provide convincing evidence that it did not benefit unduly by switching the project from expense to capital in 2003.
38. TURN's concerns regarding line extension allowances for existing customers should be brought up in conjunction with A.05-10-019.
39. DRA's request that the Commission extend the rate case cycle associated with SCE's test year request to four years should be denied.
40. SDG&E's request to establish the CCIM for SONGS should be denied.
41. Consideration of balancing account treatment for SDG&E's share of SONGS should be considered in the context of SDG&E's next general rate proceeding, where overall shareholder and ratepayer risks and benefits can be evaluated in a more cohesive manner.
42. Based on the results of this decision, the Settling Parties should jointly determine the levels of expenditures that will be subject to SCE's commitment to either spend the authorized amounts or credit ratepayers for the underspent amounts. When SCE files its compliance advice letter to submit the preliminary statement to establish the operation of the RIIM, it should include that jointly determined information, with supporting workpapers.
43. The November 2, 2005 SCE, CUE and TURN stipulation regarding the RIIM should be approved.
44. The employee safety incentive mechanism should be discontinued for the test year 2006 GRC cycle.
45. In its next GRC, SCE should report on its evaluation of the reliability of its injury and illness data and address its concern about whether OSHA recordable injuries should be used as the basis for an employee safety incentive mechanism. SCE should also provide information or data that demonstrates that, absent the incentive mechanism, the company has made, and will continue to make, employee safety a high priority during the full term of this GRC cycle.
46. The September 8, 2005 SCE, WMA and TURN settlement regarding bill calculation services for submetered mobile home parks should be approved.
47. With the effective date of this decision, SCE should transfer the GRC RRMA balance to its Base Revenue Requirement Balancing Account, and SDG&E should transfer the SRRMA balance to its Non-fuel Generation Balancing Account.
IT IS ORDERED that:
1. Application (A.) 04-12-014 is granted to the extent set forth in this Order. Southern California Edison Company (SCE) is authorized to collect, through rates and through authorized ratemaking accounting mechanisms, the 2006 test year base rate revenue requirements set forth in Appendix C.
2. SCE shall transfer the General Rate Case Revenue Requirement Memorandum Account balance, as of the effective date of this decision, to its Base Revenue Requirement Balancing Account.
3. Within 10 days of the effective date of this order, SCE shall file revised tariff sheets to implement the revenue requirements, accounting procedures, and charges authorized in this Order and to incorporate the relevant findings and conclusions of this decision. The revised tariff sheets shall become effective on filing, subject to a finding of compliance by the Energy Division, and shall comply with General Order 96-A. The revised tariff sheets shall apply to service rendered on or after their effective date.
4. San Diego Gas & Electric Company (SDG&E) shall transfer the San Onofre Nuclear Generation Station (SONGS) Revenue Requirement Memorandum Account Balance, as of the effective date of this decision, to its Non-fuel Generation Balancing Account.
5. SDG&E's request that the amounts authorized by D.04-12-015 for its SONGS Security Costs Balancing Account should no longer be subject to refund is granted.
6. Exhibit 900 is received in evidence.
7. SCE is authorized to implement its proposed revenue balancing account to adjust for sales variations and its proposed Post-Test Year Ratemaking (PTYR) mechanism for both 2004 and 2005 to the extent consistent with the foregoing discussion, findings of fact, and conclusions of law.
8. SCE shall establish a two way balancing to record the ongoing expenses and capital related costs associated with the Mohave Generating Station (Mohave).
9. At an appropriate time, after the permanent status of Mohave is determined, SCE shall file an application seeking a final determination of the reasonableness of the costs recorded to the Mohave balancing account.
10. The Petitions to Intervene filed by the Just Transition (Coalition) and the Navajo Nation are granted for the limited purpose of considering the Coalition's Motion for a "Just Transition" in Response to Closure of the Mohave Generating Station (Motion).
11. That part of the Coalition's Motion that requests creation of a new Mohave Sulfur Credit Sub-Account in SCE's Energy Resource Recovery Account tariff is granted. SCE shall establish that sub-account and separately track as a credit entry the revenues from the sales of SCE's sulfur credits created by Mohave's closure, effective December 31, 2005.
12. SCE shall not disburse funds from the Mohave Sulfur Credit Sub-Account without specific Commission authorization to do so.
13. That part of the Coalition's Motion that requests the Commission to expeditiously decide, as part of this consolidated proceeding, if and how proceeds from the sale of sulfur credits would be distributed to the Hopi Tribe and Navajo Nation is denied and shall be addressed elsewhere.
14. If there is a timely determination that Mohave will return to service, the issue of the distribution of revenues from the sale of Mohave sulfur credits shall be addressed as part of SCE's application to be filed in compliance with Ordering Paragraph 9 of D.04-12-016 and shall be litigated in that subsequent proceeding.
15. If Mohave is shut down or the resolution of Mohave's future operating status is delayed, SCE should file an application, no later than January 1, 2007, for authority to disburse funds accumulated in the Mohave sulfur credit sub-account along with a proposal for such disbursement.
16. SCE shall establish and implement appropriate procedures to satisfy our requirements as specified above in the conclusions of law related to the proposed Project Development Division.
17. In its next GRC, SCE shall submit the results of an audit of its compliance with the requirements of D.99-09-070 which adopted SCE's Gross Revenue Sharing Mechanism for revenues received from its non-tariffed products and services. As part of this audit, SCE shall review its determination and recording of incremental and non-incremental costs related to non-tariffed products and services from the adoption of D.99-09-070 (September 1999) through the recorded base year for its next GRC.
18. SCE shall continue the service guarantee program as adopted in D.04-07-022.
19. The August 29, 2005 SCE, Division of Ratepayer Advocates (DRA) and The Utility Reform Network (TURN) stipulation regarding the Priority 5 issue is approved.
20. SCE shall continue its one-way balancing account for Research Development and Demonstration expenditures.
21. SCE shall track the authorized and recorded Results Sharing costs in a memorandum account. When the actual Results Sharing payouts for 2006, 2007 or 2008 are determined, any shortfall in the payment to employees when compared to the authorized amount for that particular year shall then be credited to the Base Revenue Requirement Balancing Account.
22. SCE shall establish a two-way balancing account for pension costs, beginning with the 2006-2008 forecast period. The balancing account shall record the difference between actual and forecast costs and should be amortized beginning in 2009. Any accumulated balance shall receive interest at the commercial paper rate, consistent with treatment of interest accruals for other SCE balancing accounts.
23. SCE shall establish a memorandum account to track the revenue requirement associated with its forecasted and recorded 2004 and 2005 plant additions. When plant additions are evaluated for the Capital Additions Adjustment Mechanism, SCE shall evaluate 2004 and 2005 recorded plant additions as described in the conclusions of law and credit ratepayers as necessary.
24. DRA's request that the Commission extend the rate case cycle associated with SCE's test year request to four years is denied.
25. SDG&E's request to establish the Cost Control Incentive Mechanism for SONGS is denied.
26. The November 2, 2005 SCE, California Utility Employees and TURN stipulation regarding the Reliability Investment Incentive Mechanism is approved.
27. SCE's employee safety incentive mechanism shall be discontinued for the test year 2006 general rate case (GRC) cycle. In its next GRC, SCE shall provide information or measurable data to demonstrate that, absent such mechanism, employee safety has been and will continue to be a high priority over the entire general rate case cycle.
28. In its next GRC, SCE shall report on the evaluation of its injury and illness data and address concerns regarding the use of Occupational Safety and Health Administration recordable injuries as the basis for an employee safety incentive mechanism.
29. The September 8, 2005 SCE, Western Manufactured Housing Community Association and TURN settlement regarding bill calculation services for submetered mobile home parks is approved.
30. Application 04-12-014 and Investigation 05-05-024 are closed.
This order is effective today.
Dated May 11, 2006, at San Francisco, California.
MICHAEL R. PEEVEY
President
GEOFFREY F. BROWN
DIAN M. GRUENEICH
RACHELLE B. CHONG
Commissioners
Commissioner John A. Bohn, being
necessarily absent, did not participate.
APPENDIX A
List of Appearances
Applicant: James M. Lehrer, Frank A. McNulty, Megan Scott-Kakures and Sumner J. Koch, Attorneys at Law, and Russell G. Worden and Bruce Foster, for Southern California Edison Company.
Interested Parties: Angela S. Beehler, for Wal-Mart Stores, Inc., Sam Walton Development Complex; William H. Booth, Attorney at Law, for California Large Energy Consumers Association; McCracken, Byers & Haesloop, by David J. Byers, Attorney at Law, for California City-County Street Light Association; Carrie Camarena, Deputy General Counsel, for the Greenlining Institute; Elizabeth A. Collier, Attorney at Law, for Pacific Gas & Electric Company; Goodin, MacBride, Squeri, Ritchie & Day, LLP, by Brian T. Cragg, Attorney at Law, for Independent Energy Producers Association and by James D. Squeri, Attorney at Law, for California Retailers Association and California Building Industry Association; Douglas & Liddell, by Daniel W. Douglass, Attorney at Law, for Direct Access Customer Coalition and Western Power Trading Forum and by Gregory S. G. Klatt, Attorney at Law, for Alliance for Retail Energy Markets; Department of the Navy, by Norman J. Furuta, Attorney at Law, for Federal Executive Agencies; Morrison & Foerster, LLP, by Peter Hanschen, Attorney at Law, for Agricultural Energy Consumers Association; Marcel Hawiger, and Nina Suetake, Attorneys at Law, for The Utility Reform Network; Manatt, Phelps & Phillips, LLP, by David L. Huard, Attorney at Law, for Catholic Healthcare West, by Randall W. Keen, Attorney at Law, for Lowe's Home Improvement, and by Margaret E. Snow, for County of Los Angeles; Adams, Broadwell, Joseph & Cardozo, by Marc D. Joseph, Attorney at Law, for Coalition of California Utility Employees; Alcanter & Kahl, by Evelyn Kahl, Attorney at Law, for Energy Producers and Users Coalition and by Nora E. Sheriff, Attorney at Law, for Cogeneration Association of California; Sutherland, Asbill & Brennan, LLP, by Keith R. McCrea, Attorney at Law, for California Manufacturers & Technology Association; Andersen & Poole, by Edward G. Poole, Attorney at Law, for Western Manufactured Housing Communities Association; JBS Energy, by Gayatri Schilberg, for The Utility Reform Network; Laura J. Tudisco, Paul Angelopulo, Gregory Heiden, and Nicholas Sher, Attorneys at Law, for Office of Ratepayer Advocates; James T. Walsh and Glen J. Sullivan, Attorneys at Law, and Ronald Vanderleeden, for San Diego Gas & Electric Company; James Weil, Director, for Aglet Consumer Alliance.
State Service: Mark Bumgardner, Martin G. Lyons and Robert M. Pocta, for Division of Ratepayer Advocates; Donald J. LaFrenz and Laura Lei Strain, for the Energy Division.
(END OF APPENDIX A)
APPENDIX B
List of Acronyms and Abbreviations
A. - Application
AB - Assembly Bill
A&G - Administrative and General
ACMI - Average Customer Minutes of Interruption
AFUDC - Allowance for Funds Used During Construction
Aglet - Aglet Consumer Alliance
ALJ - Administrative Law Judge
AR - Automatic Recloser
AReM - Alliance for Retail Energy Markets
ARO - Asset Retirement Obligation
BOON - Best Option Outside Negotiation
BOR - Board of Review
BURD - Buried Underground Residential Distribution
CAAM - Capital Additions Adjustment Mechanism
CAC - Customer Advances for Construction
CARE - California Alternate Rates for Energy
CEC - California Energy Commission
CIAC - Contributions In Aid of Construction
CPI - Customer Price Index
CPM - Cost Per Meter
CPSD - Consumer Protection and Safety Division
CRE - Corporate Real Estate
CS&I - Customer Service and Information
CSBU - Customer Service Business Unit
CTC - Competition Transition Charge
CUE - Coalition of California Utility Employees
D. - Decision
DA - Direct Access
DBT - Design Basis Threat
DACC - Direct Access Customer Coalition
DACRS - Direct Access Cost Responsibility Surcharge
DRA - Division of Ratepayer Advocates
E&BD - Economic and Business Development
ECAC - Energy Cost Adjustment Clause
EDR - Economic Development Rate
EH&S - Environmental Health and Safety
EIP - Executive Incentive Compensation Plan
EIX - Edison International
ERISA - Employee Retirement Income Security Act
ERRA - Energy Resources Recovery Account
ES&M - Energy Supply and Management
FASB - Financial Accounting Standards Board
FERA - Family Energy Rate Assistance
FERC - Federal Energy Regulatory Commission
FTEs - Full Time Equivalents
FFO - Funds From Operations
Four Corners - Four Corners Generating Station
FTEs - Full Time Equivalents
GRC - General Rate Case
Greenlining - Greenlining Institute
HMWD-PE - High Molecular Weight Polyethylene
HP - Health Physics
HR - Human Resources
Hydro - Hydroelectric
I. - Investigation
ICIP - Incremental Cost Incentive Program
IEPA - Independent Energy Producers Association
IMM - Interdepartmental Market Mechanism
INPO - Institute of Nuclear Power Operations
IT - Information Technology
M&S - Materials and Supplies
MBE - Minority Business Enterprise
MHP - Mobile Home Park
MIP - Management Incentive Program
Mohave - Mohave Generating Station
Moody's - Moody's Investor Services
MOU - Memorandum of Understanding
NARUC - National Association of Regulatory Utility Commissioners
NEI - Nuclear Energy Institute
NRC - Nuclear Regulatory Commission
O&M - Operations and Maintenance
OCM - Organizational Change Management
OD - Organizational Development
OOR - Other Operating Revenue
ORA - Office of Ratepayer Advocates
P&B - Pensions and Benefits
PBOP - Post-Retirement Benefits Other Than Pensions
PBR - Performance-Based Ratemaking
PDD - Project Development Division
PG&E - Pacific Gas and Electric Company
PHFU -- Plant Held for Future Use
PILC - Paper Insulated Lead Covered
PPA - Purchased Power Agreement
PROACT - Procurement Related Obligations Account
PTY - Post-Test Year
PTYR - Post-Test Year Ratemaking
PX - Power Exchange
QF - Qualifying Facility
RD&D - Research Development and Demonstration
RDAM - Reliable Distribution Accountability Mechanism
RIIM - Reliability Investment Incentive Mechanism
RRMA - Revenue Requirement Memorandum Account
SAM - Structural Analysis Methodology
SCE - Southern California Edison Company
SDG&E - San Diego Gas & Electric Company
SFAS - Statement of Financial Accounting Standard
SIRP - Substation Infrastructure Replacement Program
SoCalGas - Southern California Gas Company
SONGS - San Onofre Nuclear Generating Station
SRRMA - SONGS Revenue Requirement Memorandum Account
T&D - Transmission and Distribution
TDBU - Transmission and Distribution Business Unit
TRMC - Transformer Resource Management Committee
TURN - The Utility Reform Network
WMA - Western Manufactured Housing Community Association
WMDVBE - Women, Minority and Disabled Veterans Business Enterprise
WPTF - Western Power Trading Forum
(END OF APPENDIX B)
