XIX. Assignment of Proceeding

Michael R. Peevey is the Assigned Commissioner and Jeffrey P. O'Donnell is the assigned ALJ in this proceeding.

Findings of Fact

1. SDG&E has elected not to participate in the SGRP.

2. SONGS is currently licensed by the NRC to operate until 2022.

3. SCE has presented a prima facie case in this proceeding.

4. As a result of SDG&E's decision not to participate in the SGRP, and pursuant to the operating agreement between the owners of SONGS, SDG&E's ownership share of SONGS will be reduced, and SCE's ownership share will be increased in the same amount if the SGRP is performed.

5. The timing of the SGRP is dependent upon the degradation of the original steam generators, and the availability of replacement steam generators.

6. Other utilities have requested and received higher plugging limits from the NRC.

7. The SGRP is needed if SONGS is to continue operating through the end of its license lives.

8. If the SGRP is to go forward, any delay in doing so would result in more monies being spent to repair and maintain the original steam generators, and store the replacement steam generators, without a corresponding decrease in the cost of the SGRP.

9. The replacement steam generators will not be available before 2009.

10. SCE's estimate of the cost of the SGRP is $680 million ($569 million for replacement steam generator installation, and $111 million for removal and disposal of the original steam generators), of which $141 million (26%) is for contingencies.

11. SCE states that the level of contingencies in its estimate is sufficient to cover all known risks.

12. No party has represented that SCE's SGRP cost estimate is too high.

13. In Decision 05-11-026 the maximum allowable SGRP cost for PG&E's Diablo Canyon nuclear power plant included a 15-percent allowable cost above PG&E's cost estimate subject to reasonableness review to account for future cost uncertainties.

14. We find it reasonable to allow SCE to incur costs subject to reasonableness review 15-percent in excess of the $680 million total SGRP cost estimate. There is a cost cap of $782 million, and SCE can not collect cost in excess of that cap.

15. SCE states that its high O&M cost estimate, 10% above its 2006 GRC estimate, reasonably bounds most unforeseeable regulatory and extraordinary operating expenses

16. O&M costs may be subject to change.

17. Recorded RFO O&M costs for RFOs 12 and 13 were higher than the amount included in SCE's 2006 GRC forecast.

18. One-time costs for Unit 3's RFO 14 will exceed SCE's forecast.

19. SCE's SONGS O&M budget for 2004 was $40 million above the amount forecasted in its 2003 GRC.

20. SCE's base O&M forecast based on its 2006 GRC is about 12% higher than its initial forecast in this proceeding.

21. SCE's history with respect to O&M costs demonstrates that O&M costs are likely to exceed its estimates, and that there will likely be future O&M expenses that are not currently known.

22. SCE states that its high capital additions estimate reasonably bounds the uncertainty inherent in its capital additions forecast.

23. Capital additions may be subject to change.

24. A fire in 2001, which was started by a worn-out circuit breaker, resulted in $100 million in unanticipated capital costs.

25. The need for the $64 million reactor head replacement project was not known a year previously.

26. The 25% historical variance between capital additions estimates five years in advance and actual expenditures reflects the fact that there will be unanticipated costs due to ageing, changing NRC requirements, or some other reason.

27. There is no basis in the record for estimating the probability of the occurrence of future increased security requirements or their timing.

28. CEC's assumption that lesser additional security requirements would be imposed if SONGS is shut down at the time of imposition is unlikely.

29. Based on CEC's representations most, if not all, of any new security requirements would be imposed on SONGS with or without the SGRP.

30. The costs estimated by CEC are illustrative examples rather than estimates based on known requirements.

31. The possibility of future increased security requirements supports our conclusion that some increase in future O&M costs and capital additions above the amount forecast by SCE is appropriate.

32. The effect of a one-year outage on the SGRP's cost-effectiveness will vary, depending on when it occurs, due to the time value of money.

33. Since the discount rate generally exceeds the escalation of the cost components in the cost-effectiveness analysis, the effect of a one-year outage decreases over time.

34. Utilizing a 4% reduction in the capacity factor as a proxy for a one-year outage spreads the outage over the remaining life of the plant, which means that the actual costs of a one-year outage could be a greater or lesser amount depending on when it occurs.

35. The record does not demonstrate that a one-year outage is likely.

36. In D.03-12-059, the Commission authorized SCE to enter into a power purchase agreement with MPC for the purchase of electricity from Mountainview.

37. Mountainview is a CCGT with a target heat rate of 7,100 Btu/kWh, which is the heat rate for the new plant after no more than 100 hours of operation.

38. The target heat rate is not the heat rate that would be expected over Mountainview's life.

39. The heat rate over Mountainview's life would likely be higher than the target heat rate due to the effects of ageing.

40. SCE's forecast heat rate is approximately 2% higher than the Mountainview target heat rate.

41. By D.04-06-011, the Commission authorized SDG&E to execute the Otay Mesa PPA.

42. Otay Mesa is a CCGT with guaranteed baseload and peak heat rates of 6,971 and 7,230 Btu/kWh, respectively.

43. The actual heat rates achieved by Otay Mesa will be between 6,971 and 7,230 Btu/kWh, or within 4% of the value used by SCE.

44. Otay Mesa has water available for cooling, which helps it achieve its low heat rate.

45. The Otay Mesa PPA is only for the first 10 years of the plant's life.

46. The heat rate over the life of Otay Mesa will likely be higher than the guaranteed baseload and peak heat rates due to the effects of ageing.

47. The guaranteed heat rates for Otay Mesa are for the first ten years of the plant's life, not its entire operating life.

48. The heat rate used by SCE is for the life of a CCGT, as opposed to the first 100 hours or ten years of operation, and is within 4% of the heat rates used in D.03-12-059, and D.04-06-011.

49. SDG&E's long-term resource plan, which includes a 500kV transmission line in the 2010 time frame, was found in D.04-12-048 to be reasonable to satisfy SDG&E's transmission grid reliability needs.

50. If the SGRP is not performed, it appears that Unit 3, and likely Unit 2, will continue in operation beyond 2010.

51. There is sufficient time for SDG&E to construct a 500kV transmission line in the 2010 time frame to satisfy its transmission grid reliability needs.

52. Since a transmission line will be built by SDG&E, regardless of whether the SGRP is undertaken, that will be available to mitigate the effect of SONGS shutdown, and we are addressing only SCE's costs for transmission mitigation if SONGS shuts down, we need only address the amount of voltage support equipment needed by SCE.

53. Both SCE and SDG&E agree that additional voltage support equipment will be needed to mitigate against SONGS shutdown.

54. SCE's three scenarios indicate an average of 1,136 MVARs of voltage support equipment to be installed by SCE.

55. SDG&E estimates the total requirement for it and SCE at 598 MVARs, of which 354 MVARS would be attributable to SCE's transmission system.

56. SCE adjusted the DEI forecasts to include subjective components to account for changes in industry experience, and NRC guidance and requirements.

57. For Unit 2, referring to only the past DEI forecasts without any subjective adjustment by SCE, the RFO 11 and RFO 12 actual repairs were both 30% less than forecast, and the RFO 13 actual repairs were 6% less than forecast. For Unit 3, the RFO 12 actual repairs were 3% more than forecast, and the RFO 13 actual repairs were 55% less than forecast.

58. Since actual repairs were generally less than DEI's forecast repairs, and DEI's forecast repairs were based on forecast tube degradation, actual tube degradation was generally less than forecast by DEI.

59. SCE's subjective adjustment was an increase of 6% for Unit 2, and an increase of 12% for Unit 3.

60. Since the more recent DEI forecast used by SCE decreased, and SCE's forecast was unchanged, SCE effectively increased its subjective adjustment from 6% to 12% for Unit 2. SCE has not explained why such an increase in its subjective adjustment is reasonable.

61. The record demonstrates that there is considerable uncertainty as to when the steam generators will reach the plugging limit.

62. The most recent DEI forecasts indicate a 32% probability of Unit 2 reaching the plugging limit by RFO 17 in July 2011, and a 70% probability of reaching the plugging limit by RFO 18 in April 2013. These forecasts also indicate a 46% probability of Unit 3 reaching the plugging limit by RFO 19 in January 2016. This means that without the SGRP, there is approximately a 50% probability that Unit 2 will operate until mid-2012, and that Unit 3 will operate until the beginning of 2016.

63. If SCE was to apply for and be granted a higher plugging limit by the NRC, the original steam generators would be allowed to run longer than forecast, but SCE has not done so.

64. In D.85-08-046, the Commission addressed the recovery of the remaining undepreciated plant investment in Humboldt that was shut down before the end of its license life. The Commission allowed a four-year amortization of the remaining unrecovered plant investment without a return on the unamortized balance during the amortization period.

65. In D.92-08-036, the Commission addressed the recovery of remaining undepreciated plant investment for Unit 1, which was shut down before the end of its license life. The Commission adopted a settlement that allowed a four-year amortization of the remaining unrecovered plant investment. It also allowed a return equal to the embedded cost of debt on the unamortized balance during the amortization period. Since this decision adopted a settlement, it did not set a precedent.

66. It is premature to make determinations on the ratemaking treatment of an undepreciated plant balance in the event of an early shutdown, and there is no fixed policy as to how any undepreciated plant balance would be recovered, if at all.

67. The authorized cost of capital is often used as a discount rate to evaluate cost-effectiveness.

68. Since most of the costs in this cost-effectiveness evaluation occur in the early years of the SGRP, whereas most of the benefits occur later, the use of a higher discount rate would tend to make the SGRP less cost-effective, and the cost-effectiveness analysis more conservative.

69. SCE's recommended 10.5% discount rate is higher than its authorized cost of capital, and no party has recommended a specific higher discount rate.

70. The record is not sufficient to determine whether, in theory, an incremental cost of capital is more appropriate as a discount rate than the authorized cost of capital.

71. SCE currently owns 75.05% of SONGS.

72. SDG&E currently owns 20.00% of SONGS.

73. Anaheim currently owns 3.16% of SONGS.

74. Riverside currently owns 1.79% of SONGS.

75. SCE and SDG&E have agreed that SDG&E's likely remaining ownership share will be 0-14% if the SGRP goes forward.

76. While SCE and SDG&E have submitted their dispute regarding the resulting ownership reduction due to SDG&E's non-participation in the SGRP to arbitration, the result of the arbitration is not binding.

77. Anaheim has decided not to participate in the SGRP.

78. The record does not indicate what Anaheim's likely ownership share will be as a result of its non-participation in the SGRP.

79. In its application, SCE assumed that if the SGRP is not performed, Units 2 and 3 will shut down at the same time.

80. Under the split shutdown scenario, Unit 2 would shut down first and Unit 3 would remain in operation for a longer period.

81. The record demonstrates that Unit 2 will likely shut down before Unit 3, and that Unit 3 can be operated when Unit 2 is shut down.

82. In D.04-12-048 and D.05-04-024, the Commission adopted a GHG adder for carbon dioxide emissions to be used when comparing fossil generation to non-fossil generation in utility resource plans, and energy efficiency programs. The purpose of the GHG adder is to explicitly account for the financial risk associated with GHG emissions.

83. Since D.04-12-048 and D.05-04-024 did not address major repairs to nuclear power plants as an alternative to fossil fuel fired generation, they did not address whether and to what extent the GHG adder should be applied to this proceeding.

84. CCGTs will produce the emissions the GHG adder is intended to address.

85. Nuclear power plants have safety, public health, and environmental risks and effects.

86. Inclusion of nuclear power plant safety, public health, and environmental risks and effects, if they could be quantified, would decrease the cost-effectiveness of the SGRP.

87. Nothing in the record places a dollar amount on nuclear power plant safety, public health, and environmental risks and effects.

88. Inclusion of the GHG adder would increase the cost-effectiveness of the SGRP.

89. This proceeding addresses the effect of the SGRP on SCE's customers only.

90. SCE's SGRP could affect the prices for replacement steam generators, the materials and labor to install them and remove and dispose of the original steam generators, and future O&M costs associated with other SGRPs occurring at about the same time. However, since SCE's customers will not be paying for other SGRPs occurring at about the same time as the SONGS SGRP, they will not be affected.

91. While it is possible that the SGRP could affect the costs for goods and services other than those associated with other SGRPs, the record does not indicate that there would be any significant effect on SCE's customers.

92. SONGS began commercial operation in 1983 and 1984.

93. As a result of the 1987 settlement, CE inspected all steam generator tubes, reviewed relevant documentation, plugged the affected tubes, provided SCE with a $750,000 credit to cover the cost of plugging additional tubes that may experience batwing wear during future operation, and agreed that CE would perform, at its own expense, any plugging of tubes that became necessary as a result of improper annealing or batwing wear prior to the end of operations or 2023, whichever comes first.

94. The 1987 settlement addressed known problems at SONGS with annealing and batwings.

95. SONGS had not experienced stress corrosion cracking or other unanticipated corrosion at the time of the 1987 settlement.

96. The fact that the 1987 settlement did not address problems that had not occurred at SONGS at that time does not make it unreasonable.

97. The record shows that the 1987 settlement did not provide a broad release of potential steam generator corrosion claims against CE.

98. SDG&E's participation in the 1987 settlement indicates that it thought the settlement to be reasonable.

99. The 1993 settlement regarding steam generator feedrings provided SCE with $4 million in discounts on certain goods and services to be purchased from CE in future years.

100. The 1993 settlement did not include a release of claims related in any way to the steam generators that SCE either knew, suspected, or could have come to know about in the exercise of due care, although CE proposed one, which indicates that CE recognized that SCE had not previously provided such a broad release.

101. SCE and SDG&E filed the 1996 suit against CE seeking compensation for damage to the heat exchangers.

102. CE raised a counterclaim asserting a breach of the NSSS contract by SCE and SDG&E due to failure to maintain property insurance.

103. SCE and SDG&E jointly argued that since the NSSS contract had been completely performed in 1983/84, they had no continuing obligations to CE.

104. The court found, among other things, that the NSSS contract had been performed, and dismissed the 1996 suit.

105. In connection with the 1996 suit, it was SDG&E's position, as well as SCE's, that the NSSS contract warranty had expired.

106. The court's decision indicates that the NSSS contract had expired as claimed by SCE and SDG&E.

107. On a number of occasions, beginning shortly after the commencement of commercial operations, SCE pursued claims against CE, some of which were related to the steam generators.

108. SDG&E is answerable to its shareholders, and Anaheim and Riverside are answerable to their citizens for actions taken by them or on their behalf by SCE.

109. The record shows that, for example, the 1987 settlement was discussed by the SONGS Board of Review, which consists of members representing each of the owners.

110. We have no reason to believe that the other owners have or had any incentive not to sue CE concerning the steam generators if they reasonably believed there was a basis for such a suit with a reasonable chance for a favorable outcome.

111. There is nothing in the record that indicates that the other owners disagreed with SCE's actions regarding CE.

112. The record indicates that SDG&E is more than willing to make it known when it disagrees with SCE regarding matters related to SONGS.

113. It appears that the other owners agreed with SCE's actions regarding CE, which supports the reasonableness of SCE's actions regarding CE.

114. If we were to assume that SCE should have sued CE, we would have to assume that the result, if any, would have been a settlement, because the record does not indicate that any of the suits against CE were resolved other than by a settlement.

115. The record only indicates the results of two settlements with CE: Consumers Power and APS.

116. The Consumers Power suit concerned damage as a result of the use of phosphate in the water treatment. This damage mechanism was not present at SONGS.

117. The APS suit concerned a design defect in the steam generators that was unrelated to Alloy 600, and is not present at SONGS.

118. The results of the Consumers Power and APS settlements provide no basis for determining the value of a settlement, and the results of all other settlements are confidential.

119. SCE has not requested an exemption from a reasonableness review.

120. TURN's request for a separate reasonableness review of the management of the original steam generators is based primarily on its representation that SCE unreasonably denied its requests for information.

121. TURN had plenty of time to investigate the reasonableness of SCE's management of the original steam generators.

122. If TURN felt that SCE had unreasonably denied its requests for information, it should have filed a motion to compel production of the documents it requested, but it chose not to do so.

123. SCE addressed the steps it has taken to prevent, detect, mitigate, and repair the degradation of the steam generators in the record.

124. The primary benefit to SCE included in Aglet's and TURN's guaranteed savings proposals does not exist.

125. Since Aglet's and TURN's proposals guarantee ratepayers a specified level of savings, if the savings are less than the specified amount, but greater than zero, SCE would have to make payments to ratepayers even though the SGRP yields benefits to them.

126. Aglet's and TURN's guaranteed savings proposals are inequitable in that they could require a payment to ratepayers even when the SGRP is cost-effective, without a corresponding potential benefit to SCE.

127. Since, under Aglet's and TURN's guaranteed savings proposals, the basis from which savings would be determined would be an estimate of the costs that would have resulted if the SGRP had not been performed, the level of any achieved savings can only be estimated.

128. Under traditional ratemaking treatment of projects such as the SGRP, recorded expenditures earn AFUDC. When the project is completed, the expenditures and the AFUDC are put into ratebase.

129. Under SCE's construction financing proposal, it would be allowed to recover construction financing costs as they are incurred. No AFUDC would be accrued, and only the expenditures would be put into ratebase.

130. SCE's construction financing proposal is a substantial departure from normal ratemaking treatment of capital expenditures, is without precedent, and would have ratepayers paying for a project before it is used and useful to them.

131. SCE has not demonstrated that its construction financing proposal is needed in order to complete the SGRP.

132. Other than the fact that its financial ratings are lower than when it built SONGS, SCE has shown no financial need for its construction financing proposal.

133. SCE has not shown any ratepayer benefit that would offset the $3.6 million cost of its construction financing proposal.

134. The cost of removal and disposal of the original steam generators was intended to be paid for out of the trusts when SONGS is decommissioned, not out of the depreciation reserve.

135. In this case, there are two sets of steam generators, the original ones and the replacements, and costs of removal and disposal for each set.

136. By the time the SGRP is performed, roughly 80% of the removal and disposal costs of the original steam generators will have been accumulated in the trusts.

137. If the SGRP is performed, the trusts cannot be used for the original steam generators because the original steam generators will be removed and disposed of prior to decommissioning, and will be used for the replacement steam generators when SONGS is decommissioned.

138. By the time the SGRP is complete, current ratepayers will have already paid for about 80% of the cost of removal and disposal of the replacement steam generators through contributions to the trusts. If they are also required to pay for 100% of the removal and disposal costs of the original steam generators through depreciation before the SGRP is complete, they will have paid for a total of 180% of the costs of removal and disposal of one set of steam generators, thus subsidizing future ratepayers.

139. If the costs of removal and disposal of the original steam generators are charged only to future ratepayers by being depreciated over the remaining lives of SONGS after the SGRP is complete, future ratepayers will have to pay for 100% of the costs of removal and disposal of the original steam generators through depreciation, as well as 20% of the costs of removal and disposal of the replacement steam generators through contributions to the trusts. This would amount to a total of 120% of the costs of removal and disposal of one set of steam generators; thus subsidizing current ratepayers.

140. As to the issues of tax normalization and revenue requirement allocation regarding the depreciation costs, the record does not demonstrate why depreciation of the costs of removal and disposal of the original steam generators should be treated differently than other SONGS depreciation expenses.

141. R.04-09-003 pertains to gains or losses on sales of utility assets.

142. SCE has not proposed that the original steam generators be sold.

143. R.04-09-003 does not apply to the original steam generators.

144. Since R.04-09-003 is scheduled to be decided well before the original steam generators are disposed of, if a decision in R.04-09-003 should apply to them, there will be ample opportunity to do so.

145. The Commission has routinely established MAAC accounts for major capital projects and provided interim rate recovery, subject to refund, prior to the conclusion of a reasonableness review.

146. In this decision, costs are expressed in 2004 dollars.

147. Actual costs will be expressed in nominal dollars when they are recorded.

148. A meaningful comparison of recorded SGRP costs with the costs specified herein will require all costs to be converted to equivalent year dollars by an inflation adjustment.

149. The inflation adjustment should be made based on reliable publications such as the Consumer Price Index published by the U.S. Bureau of Labor Statistics.

150. The record is not sufficient to address how the inflation adjustment should be made.

151. ORA is free to ask for information at any time pursuant to § 309.5(e) and § 314(a).

152. A 92% capacity factor, an 84% capacity factor, or a one-year outage is unlikely.

153. The split shutdown scenario is more costly than shutting both units down when one unit reaches the plugging limit.

154. The base case NPV ranges between negative $310.4 million and $220.1 million.

155. It is appropriate to use base case gas prices increased by one standard deviation, or 16%.

156. Scenario 3 uses the base case with gas prices increased by one standard deviation.

157. Scenario 3 has an NPV of between $296.7 to $114.7 million, depending on SCE's ownership share.

158. The base case does not include a GHG adder that would decrease the net cost of the SGRP by $307.9-$257.1 million depending on SCE's ownership share, or the unquantified safety, public health, and environmental risks and effects associated with SONGS that would offset the GHG adder.

159. Since the record does not quantify any other safety, public health, and environmental risks and effects associated with SONGS, we do not include these factors in the NPV calculation.

160. Variations in the gas price, capacity factor, ownership percentage, O&M costs, capital additions, and SGRP costs could make the SGRP more or less cost-effective.

161. The Commission is the lead agency under CEQA with respect to the environmental review of the SGRP and preparation of the Final EIR.

162. The Final EIR is competent, comprehensive, and in compliance with CEQA.

163. The Final EIR identifies activities and potential environmental impacts that are under the exclusive jurisdiction of the federal government.

164. There are no Class I impacts from the SGRP or alternatives studied in the Final EIR.

165. The Final EIR identifies environmental effects of the SGRP and alternatives that may be mitigated or avoided.

166. The Final EIR identifies the environmentally superior alternative for the Transport Phase as transportation of the replacement steam generators inland through Camp Pendleton Marine Corps Base to the SONGS site. For the Removal Phase, the environmentally superior alternative is off-site disposal of the original steam generators. No environmentally superior alternative was identified for the Staging and Installation Phases.

167. The Final EIR finds that the environmentally superior alternatives for the Transport and Removal Phases, combined with SCE's proposals for the Staging and Installation Phases, are superior to the no project alternative.

168. The Final EIR concludes that the SGRP, with the recommended mitigation measures, will not impose any significant impact on the environment.

169. The mitigation measures identified in the Final EIR are reasonable and feasible.

170. The MMCRP conforms to the recommendations of the Final EIR for measures required to mitigate or avoid environmental impacts of the SGRP.

171. The Final EIR represents our independent judgment regarding the environmental impact of the SGRP.

172. Nothing in the Final EIR precludes the SGRP from going forward.

173. Increases in SGRP costs incurred may occur to comply with the requirements of the Final EIR.

174. Nothing in the Final EIR alters the cost-effectiveness of the SGRP.

175. Nothing in the Final EIR precludes the ratemaking treatment specified herein.

176. SGRP is cost effective. To place reasonable bounds on ratepayer and shareholder risk, we will conduct a reasonableness review if costs exceed $680 million.

177. SCE's SGRP cost estimate includes 26% for contingencies.

178. If costs exceed $680 million, the entire SGRP cost shall be subject to reasonableness review. In addition there is a total SGRP cost cap of $782 million.

179. The O&M cost estimate used in the base case is equal to the amount that SCE represents reasonably bounds the uncertainty inherent in its forecasts.

180. The capital additions estimate used in the base case is slightly greater (3%) than the amount SCE states reasonably bounds the uncertainty inherent in its forecasts.

181. The base case amounts for O&M and capital additions are 10% and 25% higher, respectively, than SCE's base case estimates, which are based on its 2006 GRC.

182. SCE's base case estimates, based on its 2006 GRC, are higher than the base case amounts originally used in its application.

183. Because O&M costs maybe subject to change, we decline to place a cap on our estimates.

184. The O&M costs and capital additions shown in Attachment A are expressed in 2004 dollars and will have to be converted to future year dollars, in proceedings such as GRCs where revenue requirements and rates are set, through the use of an inflation adjustment.

185. The inflation adjustment should be made based on reliable publications such as the Consumer Price Index published by the U.S. Bureau of Labor Statistics.

186. SCE has incurred costs related to the SGRP, and continues to do so.

187. It is possible that SCE will decide to cancel the SGRP.

188. The reasonableness of SGRP costs incurred to date has not been addressed in this proceeding.

189. On June 28, 2005, SCE filed a motion to accept the gas price forecast set forth in Advice Letter 1878-E into the record.

190. Advice Letter 1878-E was filed on March 25, 2005 pursuant to Ordering Paragraphs 1 and 24 of D.04-12-048. It contains gas price forecasts for 2005 through 2014.

191. On July 13, 2005, CEC filed a motion to reopen the record for the limited purpose of receiving into the record the executive summary of a document entitled "Safety and Security of Commercial Spent Nuclear Fuel Storage: Public Report" prepared by the National Academy of Sciences. The report addresses potential safety and security risks of spent fuel storage at commercial reactors, and potential remedies.

192. If the Commission were to direct SCE to provide the parties with cost-effectiveness model runs that incorporate changes previously proposed by TURN and other parties, such model runs would have no evidentiary value because they would not be in the record. To include them into the record, the parties would have to file the appropriate motions after receipt and review of the results. Granting such motions could necessitate additional hearings and briefs.

193. SCE presented a very different and lower gas price forecast in a June 20, 2005 workshop in R.04-04-026.

194. The Commission has in the past allowed additional information into the record without the opportunity for further hearings where the information was non-controversial and readily verifiable.

195. The Commission has determined in the past that additional information that is subject to varying interpretation and legitimate challenge cannot be resolved outside the hearing process where the parties and the Commission can test the credibility, reliability, completeness and accuracy of the information.

196. SCE's gas price forecast, which is the subject of its motion, is neither non-controversial nor readily verifiable.

197. There is no basis for allowing SCE's gas price forecast to be updated without, at the very least, allowing other parties to update their showings concerning gas price forecasts.

198. The gas price forecast is not the only issue in this proceeding.

199. There is nothing unique about the gas price forecast that would warrant treating it differently than other issues.

200. If gas price forecasts are to be updated, there is no reason that information on other issues should not also be updated by other parties.

201. If SCE's motion is granted, it will likely be necessary to require SCE to update its entire showing to incorporate other more recent developments that may be relevant.

202. In order to allow updates by other parties, SCE would have to be required to perform additional model runs for the parties.

203. Updates by SCE, CEC, and/or the other parties of their showings on gas prices and/or other issues would likely necessitate additional hearings and briefs.

204. In the time required to do the updates, hearings, and briefs, there could be additional events, such as additional gas price forecasts, refueling outages, etc. that arguably would require further updates.

205. Granting SCE's and/or CEC's motion could delay resolution of this proceeding indefinitely.

206. At some point, notwithstanding continuing developments, the record must be closed and the matter submitted for decision. That point has been reached in this proceeding.

207. Since Advice Letter 1878-E presents gas price forecasts through 2014 rather than 2022, it could not be used to calculate the cost-effectiveness of the SGRP because it is incomplete.

208. SCE's presentation of a different gas price forecast in the June 20, 2005 workshop demonstrates that the forecast in Advice Letter 1878-E is not SCE's most recent forecast.

209. SCE could have presented more recent forecasts prior to the close of the evidentiary hearings, but chose not to do so.

210. SCE argued in its reply brief that: "The time for adding evidence to this already full record is past."

Conclusions of Law

211. If the SGRP is to go forward, it should do so on the schedule proposed by SCE.

212. Since no party has expressed particular concerns with SCE's model apart from the inputs, the Commission should use SCE's model to calculate the cost-effectiveness of the SGRP in this proceeding.

213. SCE's SGRP cost estimate is reasonable for use in determining the cost-effectiveness of the SGRP.

214. Since SCE states that its high O&M cost estimate (10% above the 2006 GRC estimate) bounds most unforeseeable regulatory and extraordinary operating expenses, and we are estimating expenditures up to 17 years in advance in this proceeding, its high O&M cost estimate is reasonable and should be used in our base case.

215. Since data for 1987-2004 shows that SCE's actual capital additions exceeded its forecasts developed five years before by approximately 25%, SCE states that its high capital additions estimate (22% above the 2006 GRC estimate) reasonably bounds the uncertainty inherent in its capital forecast, and we are estimating expenditures up to 17 years in advance in this proceeding, a capital additions estimate of 25% above the 2006 GRC estimate is reasonable and should be used in our base case.

216. In Decision 05-11-026 the maximum allowable SGRP cost for PG&E's Diablo Canyon nuclear power plant included a 15-percent allowable cost above PG&E's cost estimate subject to reasonableness review to account for future cost uncertainties. It is reasonable to accord the same treatment for SCE in this decision.

217. In future ratemaking proceedings that determine the revenue requirement associated with SONGS O&M costs and capital additions, the O&M costs and capital additions estimates shown in Attachment A maybe subject to change.

218. No cap should be placed on O&M costs and capital additions.

219. Since an 88% capacity factor reflects the average capacity factor for 1996-2004, and the parties have no objection to it, it is reasonable and should be used in our base case.

220. The 7,250 Btu/kWh heat rate used by SCE is reasonable.

221. Since it unknown whether Mohave will be in service after 2005, and at what cost, there is no way to include potential Mohave generation in the cost-effectiveness evaluation of the SGRP.

222. To mitigate the effects of shutting down SONGS, 745 MVARs of voltage support equipment will need to be installed on SCE's transmission system at a cost of $78.8 million.

223. Since SCE has not shown that its subjective adjustments are reasonable, we should base our cost-effectiveness analysis on the most recent DEI degradation forecasts.

224. For determining cost-effectiveness, it is reasonable to assume the original steam generators will reach the plugging limit when the probability of doing so is 50%, the point at which there is an equal probability they will shut down at an earlier or later date.

225. The most recent DEI forecasts, without SCE's subjective adjustments, are reasonable and should be used in the Commission's cost-effectiveness analysis.

226. The Commission should calculate the cost-effectiveness of the SGRP without explicitly assuming a limitation on capital recovery if the SGRP is not performed.

227. Since SCE's recommended discount rate does not appear likely to overstate the cost-effectiveness of the SGRP, it is reasonable and should be used in the Commission's cost-effectiveness analysis.

228. Since it remains for the Commission to decide in a § 851 application whether SDG&E should participate in the SGRP and if not, what the ownership share reduction should be, the arbitration results should not be considered herein.

229. The cost-effectiveness of the SGRP should be evaluated assuming a 0-14% range of ownership by SDG&E.

230. The Commission should use an ownership range for Anaheim that is proportionately similar to SDG&E's (approximately 0-2.2%).

231. As a result of the decisions by SDG&E and Anaheim not to participate in the SGRP, SCE's ownership share will range from 82.00% to 98.21% with a midpoint of 90.10%.

232. Since whether SDG&E should participate in the SGRP is not at issue in this proceeding, the sale of all or part of SDG&E's ownership share to SCE is also not at issue, and need not be addressed in this proceeding.

233. The reasonableness of the transfer of all or part of SDG&E's ownership share to SCE will be addressed in SDG&E's future § 851 application, which we will require SDG&E to file within 120 days of adoption of this decision.

234. The tax consequences to SCE of the sale of all or part of SDG&E's ownership share of SONGS to SCE will not affect the cost-effectiveness of the SGRP.

235. The tax consequences to SDG&E of a sale of all or part of its ownership share to SCE are not at issue in this proceeding, and need not be addressed herein.

236. The Commission should consider the GHG adder and the safety, public health, and environmental risks and effects associated with SONGS in its cost-effectiveness evaluation of the SGRP.

237. The Commission should not consider the effect of the SGRP on statewide gas prices because the cost-effectiveness evaluation in this proceeding is limited to SCE's customers who will pay for the SGRP if it is approved.

238. SCE acted reasonably with respect to the 1987 settlement.

239. SCE acted reasonably in connection with the 1996 suit in asserting that the NSSS contract warranty had expired.

240. SCE would have pursued claims against CE regarding the steam generators if it reasonably believed it had a valid claim.

241. Since SONGS is owned by SCE, SDG&E, Anaheim, and Riverside, although SCE is the operating agent, it is reasonable to assume that SCE's actions regarding CE were taken with the knowledge of the other owners.

242. The other owners could and should have been aware of SCE's actions regarding CE.

243. SCE acted reasonably with regards to CE, including the 1987 settlement, the 1993 settlement, and the 1996 suit.

244. There is no basis in the record for determining what the value of a settlement would have been if SCE had sued CE and reached a settlement.

245. TURN's argument that it was denied information regarding SCE's management of the original steam generators is not persuasive.

246. There is currently no need for a separate reasonableness review of SCE's management of the original steam generators.

247. Aglet's and TURN's guaranteed savings proposals should not be adopted.

248. SCE's construction financing proposal should not be adopted.

249. Since current ratepayers will have paid for approximately 80% of the costs of removal and disposal of the replacement steam generators through contributions to the trusts by the time the SGRP is completed, they should only have to pay for 20% of the removal and disposal costs of the original steam generators through depreciation.

250. SCE should be authorized to recover through depreciation a total of 20% of its ownership share of the estimated costs of removal and disposal of the original steam generators over 2006-2011. The remaining amount should be depreciated over the remaining lives of SONGS after the SGRP is performed.

251. TURN's recommendations regarding tax normalization and revenue requirement allocation should not be adopted.

252. Aglet's recommendation that recovery of the undepreciated book value of the original steam generators be deferred until the Commission decides related issues in R.04-09-003 should not be adopted.

253. Since the stranded cost issue is not unique to the SGRP, is beyond the scope of this proceeding, and is more appropriately addressed in connection with any consideration of reopening direct access, it should not be addressed in this proceeding.

254. Since this proceeding does not address whether SDG&E should participate in the SGRP, the Commission should not address whether a cap would apply to SDG&E in this proceeding.

255. Since the ratepayers will be receiving service at that point, it is reasonable that interim rate recovery should begin when SONGS resumes commercial operation after the SGRP is complete for each unit, and the Commission should establish accounts similar to MAAC accounts for that purpose. Interim rate recovery should be implemented by advice letter filings. Such advice letter filings should include a preliminary determination of the inflation adjustment.

256. The selection of the appropriate inflation adjustment applicable to recorded SGRP costs should be addressed in SCE's application to include SGRP costs permanently in rates.

257. Since ORA has not demonstrated in this proceeding that periodic progress reports would materially assist in any future reasonableness review, the Commission should not require them at this point.

258. If the SGRP is not performed, both units would be shut down when either unit reaches the plugging limit.

259. The base case using an 88% capacity factor is reasonable and appropriate for use in determining the cost-effectiveness of the SGRP.

260. The SGRP is cost-effective.

261. The mitigation measures in the Final EIR should be adopted.

262. The Commission should adopt the MMCRP.

263. The Final EIR should be certified for the SGRP, in accordance with CEQA.

264. The SGRP should be approved, subject to the conditions imposed herein. Our approval means that we find it reasonable at this time based on the information in the record at this time. This does not mean that subsequent developments could not make it unreasonable to continue with the SGRP.

265. The Commission's approval of the SGRP should be contingent upon SCE's performance of the SGRP utilizing the environmentally superior alternatives for the Transport and Removal Phases, as well as SCE's proposals for the Staging and Installation Phases, and in compliance with the mitigation measures identified in the Final EIR.

266. The Commission's Executive Director should supervise and oversee the SGRP insofar as it relates to monitoring and enforcement of the mitigation measures described in the Final EIR.

267. The Executive Director should be allowed to delegate such duties to the Commission staff or outside staff.

268. The Executive Director should be authorized to employ staff independent of the Commission staff to carry out such functions, including, without limitation, the on-site environmental inspection, monitoring and mitigation supervision of construction of the SGRP. Such staff should be individually qualified professional environmental monitors or be employed by one or more qualified firms or organizations.

269. In monitoring the implementation of the environmental mitigation measures described in the Final EIR, the Executive Director should attribute the acts and omissions of SCE's employees, contractors, subcontractors or other agents to SCE.

270. SCE should be required to comply with all orders and directives of the Executive Director concerning implementation of the environmental mitigation measures described in the Final EIR.

271. The Executive Director should not authorize SCE to commence actual construction until SCE has entered into a cost reimbursement agreement with the Commission for the recovery of the costs of the MMCRP described in the Final EIR including, but not limited to, special studies, outside staff, or Commission staff costs directly attributable to mitigation monitoring.

272. The Executive Director should be authorized to enter into an agreement with SCE that provides for such reimbursement on terms and conditions consistent with this decision in a form satisfactory to the Executive Director. The terms and conditions of such agreement should be deemed conditions of approval of the application to the same extent as if they were set forth in full in this decision.

273. SCE's right to construct the SGRP as set forth in this decision should be subject to all other necessary state and local permitting processes and approvals.

274. SCE should be required to file a written notice in this docket, served on all parties to this proceeding, executed by an officer of SCE duly authorized (as evidenced by a resolution of its board of directors duly authenticated by a secretary or assistant secretary of SCE), to acknowledge SCE's acceptance of the conditions set forth herein. Failure to file and serve such notice within 75 calendar days of the effective date of this decision should result in the lapse of the authority granted herein.

275. The Executive Director should file a Notice of Determination for the SGRP as required by CEQA and the regulations promulgated thereto.

276. To place reasonable bounds on ratepayer risk and provide a reasonable assurance that the SGRP will remain cost-effective, the Commission should conduct a reasonableness review if costs exceed $680 million.

277. In future SCE ratemaking proceedings that determine the revenue requirement associated with SONGS O&M costs and capital additions, the amounts authorized may exceed the amounts shown in Attachment A.

278. Since the inflation adjustment was not addressed in the record, the selection of the appropriate inflation adjustment applicable to the costs shown in Attachment A should be considered in proceedings such as GRCs where revenue requirements and rates are set.

279. If SCE cancels the SGRP for any reason at any time, and requests recovery of any of the incurred costs from ratepayers, the Commission should retain the discretion to conduct a reasonableness review of the costs incurred, including cancellation costs, and to determine the appropriate ratemaking treatment, if any, of incurred SGRP costs.

280. Allowing updates of the record in other proceedings is beyond the scope of this proceeding.

281. The ALJ's ruling denying SCE's and CEC's motions should be affirmed.

282. This decision should be effective immediately so that the SGRP may proceed in a timely manner.

ORDER

IT IS ORDERED that:

283. The application of Southern California Edison Company (SCE) for approval of its steam generator replacement program (SGRP) for San Onofre Nuclear Generating Station Units 2 & 3 (collectively SONGS, separately Unit 2 or Unit 3) is approved subject to the following conditions.

284. Our approval of the SGRP means that we will not disallow SGRP costs on the basis that the decision to undertake the SGRP is unreasonable at this time.

285. The reasonable cost estimate for SGRP cost is $680 million (2004 dollars) plus accumulated Allowance for Funds Used During Construction (AFUDC) ($569 million for replacement steam generator installation, $111 million for removal and disposal of the original steam generators, and accumulated AFUDC), multiplied by SCE's ownership share. To the extent that replacement steam generator installation costs are less than $569 million, more funds may be used for removal and disposal of the original steam generators, and vice versa.

286. We do not intend to conduct an after-the-fact reasonableness review if the SGRP cost does not exceed $680 million.

287. If the SGRP cost exceeds $680 million, or the Commission later finds that it has reason to believe the costs may be unreasonable regardless of the amount, the entire SGRP cost shall be subject to a reasonableness review.

288. The maximum allowable SGRP cost is $782 million as adjusted for inflation and cost of capital. This cap applies to total SGRP costs. SCE will not be allowed to recover total SGRP costs in excess of this amount.

289. SCE may record in a balancing account the revenue requirement associated with the steam generator replacement for each unit as of the date of operation of each unit.

290. SCE may record in a balancing account the revenue requirement associated with the removal and disposal of the original steam generators for each unit as of the date removal and disposal is completed. This amount shall not include recovery of any revenue requirement associated with the amount to be recovered through depreciation pursuant to Ordering Paragraph 10.

291. SCE may include the revenue requirement associated with the balancing account balance for steam generator replacement for each unit in rates, subject to refund if a reasonableness review is performed, on January 1 of the year following commercial operation of each unit. SCE shall file an advice letter to implement the above. The rate increase shall not take place until and unless the advice letter is approved by the Commission.

292. SCE may include the revenue requirement associated with the balancing account balance for removal and disposal of the original steam generators for each unit in rates, subject to refund if a reasonableness review is performed, on January 1 of the year following completion of the removal and disposal of the original steam generators for each unit. SCE shall file an advice letter to implement the above. The rate increase shall not take place until and unless the advice letter is approved by the Commission.

293. After completion of the SGRP, SCE shall be required to file an application for inclusion of the SGRP costs permanently in rates, regardless of whether costs exceed $680 million. If a reasonableness review of such costs is performed, it shall be done in connection with the application. In the event the removal and disposal of the original steam generators is delayed significantly beyond the commercial operation of both units, it may be addressed in a subsequent application.

294. SCE is authorized to recover through depreciation a total of 20% of its ownership share ($22.2 million times its ownership share) of the estimated removal and disposal costs for the original steam generators over 2006-2011.

295. The selection of the appropriate inflation adjustment to convert the 2004 dollars adopted herein to nominal dollars will be addressed in SCE's application to include SGRP costs permanently in rates.

296. In future SCE ratemaking proceedings that determine the revenue requirement associated with SONGS operations and maintenance (O&M) costs and capital additions, the amounts authorized in rates may exceed the amounts shown in Attachment A.

297. The selection of the appropriate inflation adjustment to convert future O&M costs and capital additions as shown in Attachment A from 2004 dollars to the appropriate future year dollars shall be determined in the proceedings specified in Ordering Paragraph 12.

298. If SCE cancels the SGRP for any reason at any time, and requests recovery of any of the incurred costs from ratepayers, the Commission retains the discretion to conduct a reasonableness review of the costs incurred, including cancellation costs, and to determine the appropriate ratemaking treatment, if any.

299. SDG&E is required to file within 120 days of the adoption of decision a Section 851 application to determine the reasonableness of the transfer of all or part of SDG&E's share of SONGS to SCE.

300. The Final Environmental Impact Report (Final EIR) is certified for the SGRP, and is certified for use by responsible agencies in considering subsequent approvals of portions thereof.

301. The Mitigation Monitoring, Compliance and Reporting Program (MMCRP) included in the Final EIR is adopted.

302. SCE shall, as a condition of our approval of the SGRP, carry out the SGRP using the environmentally superior alternatives for the Replacement Steam Generator Transport Phase and the Original Steam Generator Removal, Staging, and Disposal Phase of the SGRP as identified in the Final EIR, and may utilize SCE's proposals studied in the Final EIR for the Replacement Steam Generator Staging and Preparation Phase and the Replacement Steam Generator Installation and Return to Service Phase.

303. SCE shall, as a condition of our approval of the SGRP, comply with all applicable mitigation measures as specified in the Final EIR.

304. The Commission's Executive Director shall supervise and oversee the SGRP insofar as it relates to monitoring and enforcement of the mitigation measures described in the Final EIR.

305. The Executive Director may delegate such duties to the Commission staff or outside staff.

306. The Executive Director is authorized to employ staff independent of the Commission staff to carry out such functions including, without limitation, the on-site environmental inspection, monitoring and mitigation supervision of construction of the SGRP. Such staff shall be individually qualified professional environmental monitors or be employed by one or more qualified firms or organizations.

307. In monitoring the implementation of the environmental mitigation measures described in the Final EIR, the Executive Director shall attribute the acts and omissions of SCE's employees, contractors, subcontractors or other agents to SCE.

308. SCE shall comply with all orders and directives of the Executive Director concerning implementation of the environmental mitigation measures described in the Final EIR.

309. The Executive Director shall not authorize SCE to commence actual construction until SCE has entered into a cost reimbursement agreement with the Commission for the recovery of the costs of the MMCRP described in the Final EIR including, but not limited to, special studies, outside staff, or Commission staff costs directly attributable to mitigation monitoring.

310. The Executive Director is authorized to enter into an agreement with SCE that provides for such reimbursement on terms and conditions consistent with this decision in a form satisfactory to the Executive Director. The terms and conditions of such agreement shall be deemed conditions of approval of this application to the same extent as if they were set forth in full in this decision.

311. SCE's right to construct the SGRP as set forth in this decision is subject to all other necessary state and local permitting processes and approvals.

312. SCE shall file a written notice in this docket, served on all parties to this proceeding, executed by an officer of SCE duly authorized (as evidenced by a resolution of its board of directors duly authenticated by a secretary or assistant secretary of SCE), to acknowledge SCE's acceptance of the conditions set forth herein. Failure to file and serve such notice within 75 calendar days of the effective date of this decision shall result in the lapse of the authority granted herein.

313. The Executive Director shall file a Notice of Determination for the SGRP as required by the California Environmental Quality Act and the regulations promulgated thereto.

314. We affirm the Administrative Law Judge's ruling discussed herein.

315. Application 04-02-026 is closed.

This order is effective today.

Dated December 15, 2005, at San Francisco, California.


Commissioner Grueneich recused
herself from this agenda item and was
not part of the quorum in its
consideration.

ATTACHMENT A

Table of Adopted O&M Costs and Capital Additions

(2004 dollars)

Year O&M Costs Capital Additions

2009 483,009 90,458

2010 499,781 97,583

2011 523,769 92,834

2012 525,820 93,271

2013 516,780 92,645

2014 518,086 91,983

2015 521,096 94,976

2016 521,212 95,939

2017 579,514 94,162

2018 447,402 94,105

2019 590,119 76,667

2020 510,288 57,716

2021 524,595 33,517

2022 456,044 16,675

Previous PageTop Of PageGo To First Page