XVII. Assignment of Proceeding
Geoffrey F. Brown is the Assigned Commissioner and Jeffrey P. O'Donnell is the assigned Administrative Law Judge in this proceeding.
1. The SGRP is needed if Diablo is to continue operation throughout the remainder of its license lives.
2. If the SGRP is to go forward, a delay would result in more monies being spent on the original steam generators, without a corresponding decrease in the cost of the SGRP, and there would be an increased risk of a forced outage.
3. The record does not indicate the probability that the end of the current statutory prohibition on customers leaving bundled service would lead to the reduction of bundled loads served by PG&E, when the reduction would occur, or the amount of the reduction.
4. Since the load would still have to be served, it does not follow that the demand for electricity would be reduced, or that Diablo would not be needed as a result of the end of the current statutory prohibition on customers leaving bundled service.
5. There is no reason to adjust the cost-effectiveness analysis to consider the effect of the end of the current statutory prohibition on customers leaving bundled service, and no basis for determining what adjustment to make.
6. It is reasonable to assume that capital costs and O&M costs are related to Diablo's performance as measured by its capacity factors because capital and O&M costs are incurred in order to keep Diablo in operation.
7. A low capacity factor could result in increased capital or O&M expenditures to correct any plant problems that led to the low capacity factor.
8. Capital additions or additional O&M could be implemented to avoid an outage or decrease in the capacity factor.
9. There are other factors which may influence capacity factors such as regulatory requirements and plant design.
10. TURN and ORA's calculations appear to yield generally similar results to those generated by PG&E's model when similar inputs are used.
11. PG&E`s $706 million estimate did not include the $50 million in decommissioning costs due to the SGRP, but PG&E did include these costs in the cost-benefit calculation.
12. PG&E originally estimated that it would cost $182 million for the procurement contract, $339 million for the installation contract, and $185 million for owner's costs, for a total of $706 million.
13. PG&E has signed a procurement contract for $209.3 million, or approximately 15% more than its estimate.
14. Since PG&E reduced the contingency amount for the installation contract to offset the increased procurement contract costs, the updated SGRP cost estimate is $209.3 for the procurement contract, $311.7 million for the installation contract, and $185 million for owner's costs, for a total of $706 million.
15. The installation contract will be a time and materials contract rather than a fixed-cost contract.
16. Installation contract costs could be more than PG&E estimates, even if the bid it ultimately adopts is the same as the cost it estimates, if more time and/or materials are necessary to complete the project.
17. Owner's costs will be dependent to some degree on the actual costs incurred pursuant to the installation contract.
18. The SGRP could ultimately cost more than $706 million.
19. Use of $815 million as a cap would provide PG&E with some incentive to control costs, while recognizing that costs could be higher than PG&E's estimate.
20. Since the $815 million cap would be adjusted for actual inflation and cost of capital, two significant cost drivers, imposition of such a cap would not put PG&E unduly at risk.
21. A cap would limit ratepayers' exposure to cost overruns, and, to some degree, help ensure that the SGRP is cost-effective.
22. Inclusion of a higher AFUDC rate resulting from a higher cost of capital will result in a higher project cost that would tend to make the SGRP appear less cost-effective, resulting in a more conservative cost-effectiveness analysis.
23. For 2012 through 2024, PG&E escalated its 2011 O&M estimate by 2.5% for inflation, and added in costs related to planned refueling outages.
24. It is not clear from the record that PG&E's estimate of O&M costs is wrong by a specific amount, and there could be unexpected O&M costs in the future.
25. In its cost-effectiveness analysis, PG&E assumed a base level of capital additions, excluding the SGRP, of $24 million based on the average capital additions from 1997-2002.
26. Since PG&E assumed that all major capital additions necessary to operate Diablo until the end of its license lives, if the SGRP is performed, will be completed by 2015, the only capital additions in its forecast after 2015 are the base capital additions.
27. It is reasonable to assume that there will be plant additions in the future that are not known at present.
28. PG&E's estimated total annual capital additions after 2015 are less than $87 million.
29. Since PG&E's major capital additions are intended to reduce uncertainty to a substantial degree, it does not follow that PG&E's forecast of major capital additions translates to greater uncertainty as MFP appears to imply by its proposal to increase capital additions by an additional $88 million based on PG&E's forecast of major capital additions.
30. The contract for the low-pressure turbine rotor replacement project was signed in 2002, is scheduled for completion in 2005-6, and is expected to add 40 MW to Diablo's capacity.
31. The low-pressure turbine rotor replacement project is not related to the SGRP.
32. There is no reason to believe that it would be cost-effective to cancel the low-pressure turbine rotor replacement project at this time, or that the project is not needed.
33. MFP's first scenario, which assumes continued operation more than three years after enhanced security requirements are put into effect, corresponds to both the case where the SGRP is performed, and to the case where the SGRP is not performed, unless it is known at the time the requirements are put into effect that neither Diablo unit will continue in operation for more than three years.
34. Given the uncertainty as to when Diablo will shut down if the SGRP is not performed, MFP's first scenario appears to be the most likely scenario both with and without the SGRP.
35. MFP's second scenario, which has both Diablo units permanently shutting down when the enhanced security requirements are put into effect, is unlikely because it would probably be cost-effective to implement security requirements even if only one unit has a few years of life remaining.
36. MFP's third scenario, which assumes that the NRC would exempt Diablo from some of the new security requirements because it will not continue in operation for more than three years, is unlikely because it is uncertain when either of the Diablo units will shut down without the SGRP.
37. If, as MFP appears to believe, enhanced security requirements will be imposed within the next few years, the only effect on the cost-effectiveness analysis would be that the reduction in the increased O&M from $54.5 million to $11 million due to shutting Diablo down would occur at a later date.
38. There is no basis in the record for estimating the probability of the occurrence of future increased security requirements or their timing.
39. It is uncertain that lesser additional security requirements would be imposed if Diablo is shut down at the time of imposition.
40. Based on MFP's representations most, if not all, of any new security requirements would be imposed on Diablo with or without the SGRP.
41. The costs estimated by MFP are illustrative examples rather than estimates based on known requirements.
42. The possibility of future increased security requirements supports our conclusion that some increase in future capital additions and O&M expenses above the amount forecast by PG&E is appropriate.
43. In April 2004, PG&E was granted a permit by San Luis Obispo County to construct an ISFSI for spent nuclear fuel at Diablo. A condition of the permit is that PG&E must update its LTSP to incorporate data developed since the LTSP was created in 1988.
44. If the ISFSI is not approved or is delayed, Diablo could be forced to shut down in 2006 because it may not have sufficient storage for its spent fuel.
45. Neither San Luis Obispo County or the CCC have the authority to require a change to Diablo's seismic design criteria; that authority lies with the NRC.
46. The record contains no estimate of the probability that Diablo's seismic design criteria will be revised, when the revision will be imposed, whether plant modifications will be necessary as a result, or what the costs of such modifications will be.
47. There is no basis in the record for assessing the impact on the cost-effectiveness analysis of a possible revision to Diablo's seismic design criteria.
48. The possibility of future revisions to Diablo's seismic design criteria supports the conclusion that some increase in future capital additions and O&M expenses above the amount forecast by PG&E is appropriate.
49. It is by no means clear that a forced shutdown will occur in 2006.
50. If a forced shutdown were to occur in 2006, the SGRP could be stopped if necessary, and cancellation costs addressed as appropriate.
51. Since a forced shutdown in 2006 would occur before the SGRP, it would have no effect on the cost-effectiveness analysis of the SGRP.
52. TURN's analysis of plant outages does not address the causes of the outages, Diablo's similarity to the plants that experienced the outages, Diablo's vulnerability to such outages, or the degree to which PG&E has taken or plans to take actions to avoid them.
53. The probability of a 12-month outage after the SGRP is completed is dependent to a substantial degree upon the efforts of PG&E to maintain and operate Diablo.
54. The record does not demonstrate that PG&E has not or will not take action to properly maintain and operate Diablo.
55. The record does not demonstrate that PG&E has failed to comply with regulatory requirements for continued operation.
56. There is no reason to believe a 12-month outage after the SGRP is completed is likely.
57. The possibility that a 12-month outage after the SGRP is completed could occur supports our conclusion that some increase in future capital additions and O&M expenses above the amount forecast by PG&E is appropriate.
58. PG&E's estimated future capacity factors for Diablo, assuming the SGRP is performed, are 94.67% between refueling outages, and 90.6% including refueling outages.
59. The record does not demonstrate that PG&E has not or will not take actions to prevent outages and keep Diablo operating at full capacity.
60. There is no reason to believe that a capacity factor below PG&E's estimate is likely.
61. A reduction in the capacity factor due to an unexpected outage would not likely be a routine event affecting the capacity factor for both units for the entire life of the plant.
62. The gas prices forecast by PG&E for this proceeding were its expected annual burner tip gas prices based on the September 5, 2003, NYMEX closing price of forward contracts.
63. In A.04-04-003, PG&E's 2004 LTRP, it forecast gas prices based on the April 19, 2004 NYMEX closing price.
64. Because of the variability of gas costs, neither the NYMEX closing prices for September 2003 nor April 19, 2004 are necessarily better for estimating gas prices between now and 2025.
65. The CEC's November report states that the wind power numbers referred to by TURN were prepared by a consultant, and are only suggestive because actual prices will vary due to circumstances applicable to individual generation plants.
66. While the CEC's November report refers to the CEC's August report, it does not state that it supersedes the August report.
67. The CEC's November report states that its wind power price estimates do not include transmission costs.
68. Since wind power is an intermittent source, additional expenditures would be necessary to achieve the same level of dependable capacity as other alternatives such as combined cycle generation.
69. D.04-09-060 adopted energy efficiency savings goals for PG&E for 2004-2013, subject to periodic revision, that are intended to address incremental energy needs.
70. D.04-09-060 required utilities, in any applications or other filings that present projections of supply-side resource needs, pipeline or transmission needs, propose new facilities or otherwise utilize projections of energy demand, to demonstrate that such filings are fully consistent with the Commission's adopted energy savings goals.
71. This application was filed long before D.04-09-060 was adopted, and does not address incremental energy needs.
72. The goals adopted in D.04-09-060 only run through 2013.
73. Delaying the SGRP would result in costs to keep the original steam generators in operation that are better spent on the SGRP if it is to be performed.
74. PG&E's cost-effectiveness analysis assumes that if Diablo were to shut down at any time, the undepreciated plant balance in ratebase would be fully recovered from ratepayers.
75. In D.03-12-035, the Commission approved a modified settlement agreement with PG&E that provided that the URG rate base established by D.02-04-016 shall be deemed just and reasonable and not subject to modification, adjustment or reduction other than through normal depreciation.
76. PG&E signed the modified settlement agreement approved by D.03-12-035.
77. The URG rate base adopted in D.02-04-016 included the rate base amount for Diablo as of December 31, 2000.
78. A reduction in future O&M costs is beyond the scope of this proceeding except as it relates to the cost-effectiveness of the SGRP.
79. Since reduction in future O&M costs would either have no effect on the cost-effectiveness of the SGRP, or improve its cost-effectiveness, whether an O&M reduction should be imposed, or what such a reduction would be, need not be determined in this proceeding.
80. In D.92-08-036, the Commission adopted a settlement that allowed a four-year amortization of the remaining unrecovered plant investment in SONGS Unit 1, and allowed a return equal to the embedded cost of debt on the unamortized balance during the amortization period.
81. Since D.92-08-036 adopted a settlement, it did not set a precedent.
82. In D.85-08-046, the Commission allowed a four-year amortization of the remaining unrecovered plant investment in Humboldt, without a return on the unamortized balance during the amortization period.
83. It is possible that, in the event of an early shut down, the undepreciated plant balance may be amortized over a four-year period with a reduced or no return on the unamortized balance.
84. Since the Commission normally bases depreciation rates on the remaining life of the asset being depreciated, it is possible that depreciation rates for Diablo, in the absence of the SGRP, would be increased based on the shorter expected life resulting in the remaining undepreciated capital costs associated with Diablo being fully recovered over its remaining life with a return earned on the undepreciated balance.
85. A discount rate based on D.04-12-047 would be approximately equal to or less than the 8.6% discount rate used by PG&E.
86. PG&E's assumption of an 80% probability of license recapture for Unit 1 recognizes that there is a chance it will not be granted, and the Commission has no reason to believe that the assigned probability is unreasonable.
87. PG&E and all other operators of nuclear generating stations are required to carry insurance for public liability claims as a result of a nuclear accident.
88. PG&E is required to participate in a loss-sharing program among utilities that own nuclear reactors. Under the loss-sharing program, if a nuclear incident occurs at Diablo or any other nuclear generating station, PG&E may be responsible for up to $201.2 million, with payments limited to $20 million per year until PG&E has paid its full share.
89. PG&E would have to apply to the NRC to reduce or eliminate its participation in the loss-sharing program.
90. There have been no assessments under the loss-sharing program, and the record does not indicate that such an assessment is likely.
91. The record does not indicate that a reduction or elimination of PG&E's participation in the loss-sharing program would be reasonable given the corresponding reduction in liability protection.
92. There is no reason to assume that foregoing the SGRP would result in any significant reduction of PG&E's liability under the loss-sharing program.
93. The record does not demonstrate that PG&E has a tolling agreement with Westinghouse extending the statute of limitations for filing a suit.
94. Assuming that PG&E could and should have known that it had a basis for filing suit in the late 1970s at the earliest, and the early 1990s at the latest, and that the statute of limitations for filing such a suit is four years, PG&E is barred at this time from filing such a suit.
95. The question of whether PG&E should be ordered to file such a suit is moot.
96. The issue of whether PG&E should have filed a suit against Westinghouse is related to the design of the original steam generators which, in turn, is related to the reasonableness of the cost of the original steam generators.
97. If the Commission were to find, in this proceeding, that PG&E should have sued Westinghouse, and would have won or received a settlement, an appropriate result would be a reduction in the rate base attributable to original steam generators.
98. The URG rate base adopted in D.02-04-016 included the rate base amount for Diablo as of December 31, 2000, a portion of which is attributable to the original steam generators.
99. Since TURN's cost-effectiveness model yields results generally similar to PG&E's model when the same or similar inputs are used, it tends to support the validity of PG&E's model.
100. Since TURN's scenarios were intended to analyze the sensitivity of the cost-effectiveness of the SGRP to various input assumptions, and did not assess the probability of any particular scenario, they are of limited use in assessing the most likely cost-effectiveness outcome of the SGRP.
101. Since ORA's cost-effectiveness model yields results generally similar to PG&E's model when the same or similar inputs are used, it tends to support the validity of PG&E's model.
102. Market prices are lower than combined cycle generation, or combined cycle generation with 10% wind, when a 30-year combined cycle facility life is used.
103. The Commission does not have the results of the tube inspections that took place in the October-November 2004 refueling outage of Unit 2 at this time, and the results of the inspections of Unit 1 during the refueling outage in early 2004 are not in the record.
104. One unit going out of service two refueling cycles later if the SGRP is not performed would have an adverse effect on the cost-effectiveness of the SGRP equal to or less than two units going out of service two refueling cycles later due to the time value of money.
105. There is no reason to believe that a one-year outage of one unit is likely.
106. There is no reason to believe that the tube inspections during the 2004 refueling outages will extend the most probable date for one unit to go out of service without the SGRP by more than one refueling cycle.
107. The SGRP will be cost-effective, assuming the most probable date for one unit to go out of service without the SGRP is extended by one refueling cycle, the low gas price and the $815 million SGRP cost, as long as the capacity factor remains above approximately 82% (third scenario).
108. Assuming the most probable date for one unit to go out of service without the SGRP is extended by one refueling cycle, the low gas price, the $815 million SGRP cost, and a one-year outage in 2015, the SGRP remains cost-effective as long as the capacity factor remains above approximately 85% (fourth scenario).
109. Assuming that the tube inspections during the 2004 refueling outages extend the most probable date for both units to go out of service without the SGRP by two refueling cycles, the SGRP will be cost effective at the low gas price, and the $815 million SGRP cost as long as the capacity factor remains above approximately 85% (fifth scenario).
110. The Commission's cost-effectiveness analysis assumes that if the SGRP was not performed, there would be generation facilities ready and waiting to provide replacement power, which is optimistic, and may understate the SGRP's cost-effectiveness, given the fact that it would not be known for certain when either Diablo unit would shut down until it is imminent.
111. Large generating facilities of any kind, including any necessary fuel transportation facilities and electric transmission facilities, cannot be built overnight, especially given the need to obtain financing, an appropriate site, and the necessary regulatory approvals.
112. Additional unquantified benefits that derive from the SGRP are the likelihood that Diablo will remain in operation as a reliable energy source, reduced air pollution compared to fossil generation, reduced dependence on fossil fuel, and diversity of electricity resources.
113. There are additional unquantified costs that result from risks associated with the additional spent nuclear fuel that will be generated by the continued operations of Diablo due to the SGRP.
114. The SGRP costs are related to the operation of Diablo.
115. To the extent that the SGRP costs more than $706 million, the amount over $706 million will be the sum of the excess costs of the components that exceeded the estimated costs, less the sum of the cost reductions due to components that cost less than anticipated.
116. Any costs over $706 million will be a net result of the individual costs of the components.
117. It is unlikely that any costs exceeding $706 million will be due to a single component.
118. PG&E's estimate is not broken down to a fine level of detailed cost components, and the estimated cost includes significant contingencies.
119. A reasonableness review of costs over $706 million will likely necessitate a review of most, if not all, of the project costs.
120. Once the SGRP has been completed for each unit, and the unit is back in service, there is no reason to preclude PG&E from having the opportunity to earn a return on its investment.
121. It is possible that a different ratemaking treatment may be imposed when the advice letters are addressed.
122. Since the record does not demonstrate that a significant rate increase would occur due to the SGRP, there is no need to require a phase in of the rate increase.
123. By a ruling dated August 31, 2004, the ALJ granted PG&E's motions to strike the pre-filed testimonies of Namson and Ackerman.
124. Namson's testimony effectively asked that this proceeding be suspended while a recommended seismic review is conducted.
125. Namson's testimony included no estimate of: (1) the probability that such a study would be required by the NRC, (2) the probability that a study, whether ordered by the Commission or the NRC, would recommend a seismic retrofit, (3) the probability that the NRC would require a retrofit if the study recommended one, (4) the cost of the retrofit, (5) when the retrofit would be performed, and (6) whether the retrofit would be required even if the SGRP were not performed.
126. Since Namson's testimony did not specifically address the cost-effectiveness of the SGRP, the need for the SGRP, or ratemaking issues, it was beyond the scope of this proceeding.
127. The ALJ's ruling striking Namson's testimony did not remove seismic issues from consideration in this proceeding.
128. Ackerman's testimony was effectively asking that this proceeding be suspended until its recommended RFP process is completed at some unspecified time in the future.
129. Ackerman's testimony made no offer of proof as to what results its proposal would yield.
130. WPTF or its members could have made unsolicited proposals, evaluated PG&E's estimates of replacement power costs, or made its own estimates of replacement power costs, but it chose not to do so.
131. Ackerman's testimony did not address any costs or benefits.
132. Since Ackerman's testimony did not address the cost-effectiveness of the SGRP, the need for the SGRP, ratemaking issues, or issues in connection with the CEQA review, it was beyond the scope of this proceeding.
133. The ALJ's ruling striking Ackerman's testimony did not preclude WPTF from presenting testimony regarding alternate proposals to the SGRP.
134. On September 2, 2004, the ALJ issued a ruling granting PG&E's motion to strike Mayer's pre-filed testimony.
135. Since nuclear decommissioning cost revenue requirements, and the allocation to rates thereof, are not within the scope of this proceeding, Mayer's testimony was beyond the scope of his proceeding.
136. On October 13, 2004, the ALJ issued a ruling granting PG&E's motion for a protective order because failure to do so could jeopardize the ability of PG&E to pursue a suit if so ordered, and to negotiate the lowest reasonable price for contracts related to the SGRP, which could result in higher costs to ratepayers.
137. Adjustment of the $706 million reasonable cost and the $815 million cap for actual inflation should be based on reliable publications such as the Consumer Price Index.
1. If the SGRP is approved, it should be performed according to PG&E's proposed schedule.
2. Since no decision has been reached in A.04-02-026, it is premature to consider whether the risks of capacity shortages, when compared to the costs of project delays, warrant a change in the steam generator replacement schedule for Diablo at this time.
3. It is not unreasonable that PG&E's Monte Carlo simulation model does not incorporate a mathematical formula directly linking capital costs, O&M costs and capacity factors.
4. PG&E's Monte Carlo simulation model is appropriate for use in determining the cost-effectiveness of the SGRP in this proceeding.
5. PG&E's SGRP cost estimate of $706 million is reasonable.
6. The Commission should increase the installation contract cost and owner's costs to obtain a possible total SGRP cost of $815 million for use in analyzing the cost-effectiveness of the SGRP.
7. Imposition of an $815 million cap fairly balances ratepayer and shareholder interests.
8. The Commission should adopt $815 million as a cap.
9. Utilizing PG&E's AFUDC rate in evaluating this application will not adversely affect ratepayers.
10. The Commission should use a 4.5% O&M cost escalation rate after 2011.
11. Base capital additions should be increased to $87 million for the years after 2015.
12. MFP's proposal to increase capital additions by an additional $88 million based on PG&E's forecast of major capital additions should not be adopted.
13. The low-pressure turbine rotor replacement project costs should not be included in the cost-effectiveness evaluation of the SGRP.
14. MFP's cost estimates for enhanced security at Diablo should not be adopted.
15. The possibility of a forced shutdown in 2006 should not be included in the cost-effectiveness analysis of the SGRP.
16. For the reasons put forth by TURN, the Commission should use a 30-year facility life for combined cycle generation in its cost-effectiveness analysis.
17. PG&E's use of the wind power costs based on the August report is reasonable.
18. MFP's recommendation to recalculate the cost-effectiveness analysis using the energy efficiency goals and costs adopted in D.04-09-060 should not be adopted.
19. ORA's recommendation for consideration of a delay is not reasonable and should not be adopted.
20. Additional tube degradation test results from refueling outages during 2004 should be considered when they are available.
21. The Commission is precluded from reducing the undepreciated rate base, as of December 31, 2000, for Diablo in the event that the SGRP is not implemented, and Diablo shuts down before the end of its license lives.
22. It is premature to determine the ratemaking treatment of Diablo in the event of an early shutdown.
23. The Commission should calculate the cost-effectiveness of the SGRP without explicitly assuming a limitation on capital recovery if the SGRP is not performed.
24. PG&E's use of an 8.6% discount rate is reasonable.
25. PG&E's assumption of an 80% probability of license recapture for Unit 1 is reasonable.
26. The Commission would be precluded from making an adjustment to the URG rate base, as of December 31, 2000, for the original steam generators, if it were to find that PG&E should have filed suit against Westinghouse, and would have won or received a settlement from Westinghouse.
27. Since there is no basis in the record for assuming that if PG&E had filed and won a suit against Westinghouse the original stream generators would have been replaced, such a suit would not affect the need for, or the cost of, the SGRP.
28. The Commission should not adopt TURN's recommended disallowance of $56-70 million or ORA's recommended disallowance of a minimum of $18 million.
29. The Commission should use market prices for replacement energy in its cost-effectiveness analysis.
30. The Commission should preliminarily determine that the SGRP is cost-effective.
31. Section 463 provides that, for the purpose of establishing rates, the Commission shall disallow unreasonable expenditures relating to the planning, construction or operation of utility plant costing more than $50 million.
32. Section 463.5 provides that the Commission is not required to undertake a reasonableness review of recorded costs of an item of utility plant costing more than $50 million where the Commission has established an estimate of the reasonable costs. However, establishment of reasonable costs does not limit or restrict the Commission's discretion in determining the reasonableness of actual costs in subsequent proceedings.
33. If the SGRP costs do not exceed $706 million, the Commission should not intend at this time to require a reasonableness review.
34. If the SGRP cost exceeds $706 million, or the Commission later finds that it has reason to believe the SGRP cost may be unreasonable regardless of the amount, the entire SGRP cost should be subject to a reasonableness review.
35. In order to avoid issues related to allocation of costs between the units, the Commission should determine whether a reasonableness review is needed after both units are complete.
36. The Commission should not adopt Aglet's proposal for guaranteed savings from the SGRP because: (1) the likely net benefits of the SGRP are substantially less than PG&E's forecast; (2) we are not granting PG&E a blanket exemption from a reasonableness review if the costs do not exceed $706 million; (3) we are imposing a cap; and (4) Aglet's proposal would have to be based on an estimate of the costs that would result if the SGRP was not performed.
37. The Commission should allow PG&E to record in the UGBA the revenue requirement associated with plant additions up to the cap as of the date of operation of each unit.
38. The Commission should allow PG&E to include the revenue requirement associated with each unit in rates, up to $326 million for Unit 1 and $380 million for Unit 2 on January 1 of the year following commercial operation of each unit, subject to refund.
39. PG&E should be required to request authority to implement the rate increase for each unit, subject to refund, by advice letter.
40. When the SGRP is complete for both units, PG&E should be required to file an application to include the costs permanently in ratebase. If a reasonableness review is to be performed, it should be done as part of that application.
41. The Commission should not preclude the possibility of a phase in of the SGRP rate increase.
42. Since imposition of seismic requirements for Diablo is not within the Commission's jurisdiction, it does not have the authority to order any changes to Diablo if such a review of seismic requirements found that any changes were needed.
43. The Commission should affirm the ALJ's ruling striking Namson's testimony.
44. The Commission should affirm the ALJ's ruling striking Ackerman's testimony.
45. The Commission should affirm the ALJ's ruling striking Mayer's testimony.
46. The Commission should affirm the ALJ's ruling granting the motion for a protective order.
47. The Commission's approval of the SGRP should be conditioned upon PG&E's acceptance of the cap.
48. Adjustment of the $706 million reasonable cost and the $815 million cap for inflation should be based on reliable publications, such as the Consumer Price Index, to be determined in PG&E's application for permanent inclusion of the SGRP costs in rates.
IT IS ORDERED that:
1. Our preliminary conclusions regarding this application are as follows:
a. The Steam generator replacement program (SGRP) for Diablo Canyon Power Plant is cost-effective.
b. $706 million, as adjusted for actual inflation and cost of capital, is a reasonable estimate of the SGRP cost.
c. We do not intend to conduct an after-the-fact reasonableness review if the SGRP cost does not exceed $706 million, as adjusted for actual inflation and cost of capital.
d. If the SGRP cost exceeds $706 million, as adjusted for actual inflation and cost of capital, or the Commission later finds that it has reason to believe the costs may be unreasonable regardless of the amount, the entire SGRP cost will be subject to a reasonableness review.
e. The maximum allowable SGRP cost (cap) is $815 million as adjusted for actual inflation and cost of capital. PG&E will not be allowed to recover SGRP costs in excess of this amount. Therefore, our approval of the SGRP is conditioned upon PG&E's acceptance of the cap.
f. We intend to allow Pacific Gas and Electric Company (PG&E) to record in the Utility Generation Balancing Account (UGBA) the revenue requirement associated with plant additions up to the cap as of the date of operation of each unit.
g. We intend to allow PG&E to include the revenue requirement associated with each unit in rates and subject to refund, up to $326 million for Unit 1 and $380 million for Unit 2 on January 1 of the year following commercial operation of each unit. PG&E will be required to file an advice letter to request authority to implement the above rate increase, subject to refund, for each unit. The rate increase shall not take effect until and unless the advice letter is approved by the Commission.
h. After completion of the SGRP, PG&E will be required to file an application for inclusion of the costs thereof permanently in rates, regardless of whether the costs exceed $706 million. If a reasonableness review is performed, it will be done in connection with the application. The appropriate inflation adjustment to the $706 million reasonable cost and the $815 million cap should be determined therein based on a reliable publication such as the Consumer Price Index.
2. We affirm the Administrative Law Judge's rulings discussed herein.
3. By this opinion, we do not approve or disapprove the SGRP, guarantee or approve the recovery of any expenditures related thereto, or dictate the outcome of our environmental review of the SGRP pursuant to the California Environmental Quality Act (CEQA).
4. This proceeding remains open to consider the results of our environmental review of the SGRP pursuant to CEQA, and to make a final determination on the matters for which our preliminary determinations are stated herein.
This order is effective today.
Dated February 24, 2005, at San Francisco, California.
MICHAEL R. PEEVEY
President
GEOFFREY F. BROWN
SUSAN P. KENNEDY
Commissioners
Comr. Grueneich recused herself
from this agenda item and was not
part of the quorum in its consideration.
