IV. Cost Recovery for Humboldt and Colusa
A. Capital Costs
D.04-12-048 provides that the capital cost of a utility-owned project selected in an RFO shall be capped at the project bid price, and that any savings below the project bid price shall be shared 50/50 between ratepayers and shareholders. D.05-09-022 granted limited rehearing on the issue of the 50/50 sharing mechanism, but provides that the 50/50 sharing mechanism will continue to apply pending the outcome of the limited rehearing, subject to adjustment.
PG&E, Aglet and DRA each propose ratemaking for the capital costs of the Humboldt and Colusa projects that would provide PG&E the opportunity to seek recovery of capital costs in excess of the adopted initial capital cost in a reasonableness review and/or true-up the projects' final capital costs to reflect 100% of any savings below the adopted initial capital cost. The proposed decision noted that, although no party had challenged any of the proposals on this basis, these elements of the parties' proposals appeared to deviate to some degree from D.04-12-048. The proposed decision adopted a variation of these elements of the parties' proposals.
In their comments on the proposed decision, however, TURN, IEP,9 and DRA challenge the proposed decision for deviating from D.04-12-048 by allowing PG&E to seek recovery of excess capital costs pursuant to reasonableness review. This decision modifies the proposed decision to appropriately conform to D.04-12-048, as discussed below.
In summary, we approve as reasonable and adopt the project bid price as the initial capital cost for the Colusa project, including the fixed contract price, excluding incentive payments, plus PG&E's estimated owner's costs, including owner's contingency. PG&E may not seek recovery of additional costs in excess of the project bid price, except that PG&E may apply for recovery of only those additional capital costs that PG&E may incur as a result of operational enhancements to the project. We direct PG&E to adjust the initial capital cost by advice letter filing to reflect any performance incentive payments actually made, and any performance incentive penalty actually due to it under the contracts. We direct PG&E to retroactively true up the initial capital cost in the next GRC following operation to reflect 50% of any savings relative to the initial capital cost.
We approve as reasonable and adopt, as the initial capital cost for the Humboldt project, the sum of the fixed contract costs, excluding incentive payments, plus PG&E's estimated owner's costs, including a 5% contingency amount. We direct PG&E to adjust the initial capital cost by advice letter filing to reflect any performance incentive payments actually made, and any performance incentive penalty actually due to it under the contracts. PG&E may seek recovery of any additional capital costs upon a showing of reasonableness, and is directed to retroactively true up the initial capital cost in the next GRC following operation to reflect 100% of any savings relative to the initial capital cost.
We address the specifics of the adopted ratemaking for the projects' capital costs below.
PG&E requests that the Commission approve as reasonable an initial capital cost for the Humboldt and Colusa projects equal to the fixed contract costs, including incentive payments, plus PG&E's estimated owner's costs, including proposed owner's contingencies, plus net fuel costs. PG&E proposes that it be permitted to increase the initial capital cost determination for additional costs that PG&E may incur as a result of (1) a delay in the closing date, (2) operational enhancements to the project, or (3) changes to the project due to new regulatory requirements or other external events; PG&E would seek these increases by advice letter filing. PG&E also proposes to file an advice letter to update the initial revenue requirement to reflect the then-current authorized cost of capital, franchise and uncollectibles factors, and property tax factors.
PG&E proposes that it be permitted to seek recovery of any other actual costs in excess of the initial capital cost upon a showing that they are reasonable.10 Conversely, PG&E proposes to retroactively true-up the initial capital cost in the next general rate case (GRC) following operation to reflect any actual cost savings.
Aglet proposes that the Commission adopt an initial capital cost for the Humboldt and Colusa projects equal to the fixed contract costs, including incentive payments. Aglet asserts that all other non-fuel, estimated capital costs have not been reviewed for reasonableness in this proceeding and should therefore be reviewed in PG&E's next GRC and placed in rate base only if the Commission finds them reasonable and prudent. Aglet proposes that net fuel costs be reviewed in PG&E's next Energy Resources Recovery Account (ERRA) proceeding, and not capitalized as PG&E proposes.
DRA recommends that the Commission approve an initial capital cost for the Humboldt and Colusa projects equal to the fixed contract costs, excluding incentive payments, plus PG&E's estimated owner's costs, excluding PG&E's proposed owner's contingencies and certain Humboldt development costs. DRA recommends that PG&E be permitted to adjust the initial capital cost for any performance incentive payments or penalties when they are known. DRA opposes PG&E's proposal to recover other additional costs upon a showing of reasonableness in a subsequent proceeding. Instead, DRA proposes that shareholders be disallowed rate recovery of 10% the first $50 million in excess costs above the initial capital cost, and be subject to reasonableness review only of any cost overruns in excess of $50 million. DRA joins Aglet in opposing PG&E's proposal to capitalize net fuel costs and the heat rate incentive.
We find the fixed contract costs for the Colusa and Humboldt projects to be reasonable. These costs were vetted through the competitive solicitation and contract selection process, and there is no basis to further review them for reasonableness.
The fixed contract costs, other than incentive payments, shall be included in the initial annual revenue requirement. Incentive payments shall not be included in the initial capital cost until and unless they are incurred. We direct PG&E to file advice letters at that time to adjust the projects' initial capital costs to reflect actual performance incentive payments paid or actual performance penalties due to it under the contracts.
We reject PG&E's request to include potential incentive payments in the pre-approved initial capital cost, for later downward adjustment in the GRC following operation in the event they are not paid. There is no demonstration in the record that the incentive payments are likely to be incurred. The advice letter procedure provides a timely means for adjusting the initial capital cost to reflect actual incentive payments without disadvantage to PG&E. In contrast, including potential incentive payments in the pre-approved initial capital cost would unnecessarily delay any downward adjustment for non-payment until the GRC following plant operation.
Although DRA proposes that PG&E be permitted to adjust the initial capital cost to reflect incentive payments or penalties when incurred, it challenges the proposed decision's adoption of this proposal for being inconsistent with the requirement because it constitutes a "soft cap" on recoverable capital costs in violation of D.04-12-048. DRA's objection is without merit. D.04-12-048 permits recovery of all capital costs in the project bid price. Incentive payments (and penalties) are a part of the fixed contract terms, and therefore constitute part of the recoverable project bid price.
We reject DRA's proposal that the heat rate incentive (if paid) be treated as an operational cost rather than included in the capital cost estimate. The heat rate incentive, like the other contractual incentives, is a fixed contract cost that is appropriately treated like all other fixed contract costs.
We find PG&E's estimated owner's costs of the projects to be reasonable. These costs shall be included in the projects' initial annual revenue requirement.
Aglet opposes pre-approval of PG&E's estimated owner's costs because they are uncertain. Aglet points out that requiring review of uncertain costs will provide a strong incentive to minimize cost overruns. However, we recognize PG&E's interest in obtaining some amount of certainty of cost recovery before undertaking these large projects, the public interest in avoiding unnecessary regulatory reviews, and the fact that PG&E's capital cost estimates including owner's costs have been scrutinized in this proceeding and, with respect to the Colusa project, in the contract selection process.
We reject DRA's proposed adjustments to disallow recovery of the cost of outside counsel for siting work on the Humboldt project. DRA asserts that this cost is unreasonable because PG&E should be able to perform this work with its in-house counsel, and because PG&E did not support its estimate of the cost with workpapers. However, as PG&E explains, it does not have the in-house experience or expertise because it has not worked on siting issues with the California Energy Commission (CEC) or sited a power plant under CEQA for over 20 years, and based its estimate on discussions with environmental firms that routinely do this work.
DRA recommends that we remove a portion of costs associated with the Humboldt project's electrical and fuel interconnection costs on the basis that they represent a 50% contingency on top of their actual estimated costs. This is not the case. Rather, as PG&E explains, the selected electrical interconnection cost estimate falls near the lower end of the range of its estimated costs. Likewise, the selected fuel interconnection cost estimate falls within the range of its estimated costs, albeit at the top of the range. While PG&E does not explain its disparate choices between the low-end and high-end estimates, we find that the cost estimate ranges are reasonable; PG&E's selected cost estimates fall within those ranges and are therefore reasonable as well. In making this finding, we take into account that the capital cost estimate will be trued up to reflect actual costs if it turns out that PG&E's selected cost estimates overstate them, as discussed further below.
We reject DRA's and Aglet's proposal to exclude the net commissioning fuel cost for Humboldt from the initial capital cost and to instead provide for its recovery through the ERRA. PG&E's proposal to capitalize net fuel costs is consistent with the Federal Energy Regulatory Commission Uniform System of Accounts, and Generally Accepted Accounting Principles call for capitalization of net fuel costs. DRA and Aglet justify their proposal on the basis that it is consistent with ratemaking treatment recently approved for Contra Costa 8 as part of a settlement in D.06-06-035. We reject this justification as contrary to Rule 12.5 of our Rules of Practice and Procedure. ("Unless the Commission expressly provides otherwise, such adoption [of a settlement] does not constitute approval of, or precedent regarding, any principle or issue in the proceeding or in any future proceeding.") Although Aglet notes that its proposal is also consistent with D.02-10-062, we find no discussion in that decision explaining the basis for directing the utilities in that instance to recover net fuel costs through the ERRA that would justify similar treatment here.
PG&E proposes to include owner's contingencies as part of the projects' initial capital costs. PG&E proposes the contingencies to account for the risk and uncertainty that it has underestimated its owner's costs. DRA opposes any contingency for Colusa capital costs, and recommends cutting the proposed contingency for Humboldt capital costs in half. Aglet recommends that all actual costs incurred (above fixed contract costs) be reviewed for reasonableness in PG&E's next GRC.
With respect to the Colusa project, we approve PG&E's proposed owner's contingency as part of the initial capital cost. PG&E included the proposed contingency in the total Colusa project cost that was evaluated in the contract selection process that led to its selection over other contracts. It is appropriately included in the initial capital cost pursuant to D.04-12-048.
This reasoning does not apply to the Humboldt project. Unlike in the case of the Colusa project, where the project bid price, including PG&E's estimated costs and contingency, was tested against competing offers, PG&E's costs related to the Humboldt project were not tested against a market alternative. Specifically, PG&E received only one offer for a PPA for the Humboldt project, which was found to be ineligible.11 As a result, there is no competitive basis to pre-approve PG&E's proposed contingency amount or, alternatively, to hold PG&E to a price cap on its owner's costs as contemplated in D.04-12-048.
PG&E argues that its request for a contingency amount is consistent with the Commission's approval of contingencies for other large capital projects. PG&E cites to several Commission decisions, the most relevant of which is D.03-12-059 in which the Commission adopted a contingency amount of 5% of the total project cost for inclusion in the approved capital cost for
Edison's gas-fired Mountainview Power Project (D.03-12-059).12 We adopt that same contingency amount here for the Humboldt project initial capital cost. We find PG&E's requested contingency amount, like Edison's in D.03-12-059, to be excessive and contrary to the public interest because it does not encourage PG&E to contain project costs.
In its oral comments on this issue, TURN objects that the Colusa and Humboldt project costs for which PG&E seeks preapproval in this application are not identical to what was included in the projects' initial bid prices. TURN argues, therefore, that PG&E's recovery of the projects' capital costs should be capped at the sum of the fixed contract costs plus PG&E's estimated owner's costs (excluding contingency). We reject TURN's argument. It would be unfair and unreasonable to exclude any contingency from the initial capital cost while at the same time denying recovery of excess costs through reasonableness review. Furthermore, it is reasonable to expect minor contract revisions and changes in owner's cost estimates after contract selection.13 Absent a finding that such changes would have led to a different contract selection or that the additional cost included in the final project price are unreasonable, we will not disallow them from the cost recovery cap.
We authorize PG&E to file advice letters to update the initial revenue requirement to reflect changes to the Commission-authorized cost of capital, franchise and uncollectibles factors, and property tax factors prior to the first GRC following operation of the projects.
PG&E seeks authority to recover, through advice letter, an increase in the projects' capital costs that it may incur as a result of (1) a delay in the closing date, (2) operational enhancements to the project, or (3) changes to the project as a result of new regulatory requirements or other external events. PG&E also requests authority to recover any additional capital costs that it may incur pursuant to a reasonableness review.
We authorize PG&E to seek, by application for approval, an increase in the capital cost for reasonable additional costs that it may incur as a result of operational enhancements to the Colusa or Humboldt projects. We deny PG&E's request for authority to recover these costs by advice letter. It is not evident that all "operational enhancements" are cost-effective. In addition, it is not clear what an "operational enhancement" may be, or if it includes increased generation obtained outside of the competitive solicitation process which, consistent with D.04-12-048, is subject to case-by-case review.
With respect to the Colusa project, we deny PG&E's request for authority to seek recovery of any other additional costs in excess of the initial capital cost. As PG&E explains, its requested contingency amount, which we approve, reflects the risk that unforeseeable factors may adversely affect PG&E's project costs. Pursuant to D.04-12-048, we limit PG&E's recovery of capital costs to the final project bid price, as explained in our discussion above regarding owner's contingencies.
With respect to the Humboldt project, however, we authorize PG&E to file an application to recover any other reasonable costs that it may incur, including additional costs incurred as a result of a delay in the closing date or changes to the project as a result of new regulatory requirements or other external events. As discussed above in our discussion regarding owner's contingencies, there is no competitive basis to hold PG&E to a price cap on its owner's costs as contemplated in D.04-12-048. We note, however, that the pre-approved initial capital costs for Humboldt may be appropriately reviewed in the context of a request for recovery of additional costs. For example, PG&E's estimate may have overstated its actual costs for some elements of the project. Or, PG&E might have unreasonably neglected new opportunities to reduce some costs such that the incurrence of other costs would not cause it to exceed the pre-approved capital cost. We therefore put the parties on notice that the review of initially-approved Humboldt costs is properly within the scope of a reasonableness review of additional costs for the purposes of determining their reasonableness.
We deny PG&E's request for authority to seek any of these increases through advice letter filings. The advice letter procedure is appropriately used where the requested utility action has been previously approved by Commission decision. Thus, for example, it is appropriate to use the advice letter process for adjustments upon payment or receipt of incentives under the pre-approved terms of the contract. In contrast, there is no record basis to predetermine that additional capital costs associated with a delay in the closing date, operational enhancements, or undefined external events are necessarily reasonable.
We reject DRA's excess capital cost sharing proposal. Pursuant to D.04-12-048, PG&E is not allowed recovery of any capital costs in excess of its Colusa project bid price. Consistent with our treatment of the Mountainview Power Project capital costs, having approved a reasonable owner's contingency amount as part of the Humboldt initial capital cost, we intend to review any additional costs in excess of this amount.
PG&E proposes to retroactively true-up the initial capital cost of the Colusa and Humboldt projects in the next GRC following operation to reflect any actual cost savings. We adopt PG&E's unopposed proposal for the Humboldt project. For the Colusa project, as required by D.04-12-048, any actual cost savings (other than incentive penalty payments) will be shared 50/50 with shareholders.
C. Operations and Maintenance Costs
PG&E requests that the Commission adopt its estimate of ongoing non-fuel Operations and Maintenance (O&M) costs, including fixed and variable O&M costs, plus a contingency factor, for purposes of establishing the initial revenue requirement for the Humboldt and Colusa projects. PG&E proposes to file an advice letter to adjust the initial revenue requirement for changes to its O&M expense forecast that may occur as a result of (1) operating the plants other than as assumed in the forecasts,14 (2) increased staffing levels due to permitting requirements, and (3) a delay in the commercial operation date, which will delay the timing of the O&M expense streams. PG&E proposes that the Commission continue to scrutinize the reasonableness of the cost of owning and operating the facilities throughout their lives in GRCs, consistent with traditional cost-of-service ratemaking.
DRA opposes any contingency factor for Colusa O&M expenses, and recommends a lower contingency factor for Humboldt O&M expenses than PG&E requests. DRA also recommends a lower staffing level assumption for Humboldt O&M expenses.
TURN asserts that the Colusa PPA bid is better for ratepayers than the Colusa PSA bid. In order to at least partly compensate for the Colusa PSA's alleged lower value, TURN proposes performance incentive mechanisms for Colusa's heart rate, availability and capacity, and 50/50 sharing between ratepayers and shareholders of any costs above PG&E's O&M forecast (with contingency) and any savings below PG&E's O&M forecast (without contingency) through ERRA, adjusted for various factors. TURN explains that these incentives are necessary in order to subject this utility-owned generation to similar performance standards as third-party generation projects, which it maintains is particularly necessary here, where PG&E turned down an economically attractive PPA for the same plant in favor of the PSA. As discussed above with respect to whether the projects reasonably meet ratepayers' needs, we reject TURN's premise that PG&E was unreasonable in choosing the PSA over the PPA, and therefore also reject TURN's proposed performance incentive mechanisms.
In its comments on the proposed decision, TURN objects that it does not premise its proposal on the existence of the PPA offer, noting that the Commission adopted similar performance incentives for Edison's Mountainview project and San Diego Gas & Electric Company's Palomar plant. Specifically, TURN points to PG&E's rebuttal testimony, which raises this point and compares TURN's proposed incentives to those adopted for Mountainview and Palomar. PG&E's rebuttal testimony does not persuade us to adopt TURN's proposal. To the contrary, PG&E's rebuttal testimony demonstrates that the penalties under TURN's incentive proposal are more onerous than those adopted for Mountainview and Palomar, and that the incentives may work against ratepayer interests by giving PG&E an incentive to maximize Colusa's availability in order to achieve incentive payment, for example, in good hydro years when PG&E could meet summer energy needs with less cost to ratepayers.
TURN asserts that the proposed decision is arbitrary and capricious for rejecting its proposal without distinguishing Colusa from Mountainview and Palomar. However, the simple fact that the Commission adopted performance incentives for Mountainview and Palomar is not cause to adopt them here for Colusa. TURN did not offer evidence or argument for doing so beyond its argument, which we reject, that PG&E was unreasonable in choosing the PSA over the PPA. We do not err by failing to address a nonexistent showing.
TURN recommends for the Humboldt project, and also for the Colusa project if the Commission rejects its O&M cost sharing recommendation, (1) reducing PG&E's estimated payroll tax burden from 9.8% to 7.84% of labor costs consistent with PG&E's forecast in its pending 2007 test year GRC, (2) one-way balancing account for PG&E's recovery of its proposed contingencies, and (3) including contractual services agreement costs and consumables in ERRA until first GRC after commercial operation.
We adopt, for purposes of establishing an initial revenue requirement for the Colusa and Humboldt projects, PG&E's O&M forecast estimate, adjusted to reflect the current payroll tax forecast, and excluding PG&E's proposed contingency factors.
PG&E asserts that the payroll tax forecast adjustment is unnecessary because it would only minimally change the first year O&M estimates, and emphasizes that the O&M estimates are just that: estimates. Neither explanation justifies our using other than the best information we have at the time we adopt a revenue requirement.
We reject DRA's recommendation that the Humboldt O&M forecast be adjusted to reflect a lower staffing level. DRA asserts that a lower staffing level is appropriate because the developer itself recommended a lower staffing level than PG&E assumes. PG&E explains that it assumes a higher staffing level in order to ensure high reliability and quick start-up and shut-down that is particularly necessary in Humboldt's transmission-constrained area. PG&E's assumed Humboldt staffing level is reasonable.
PG&E requests that we add contingency factors to its O&M forecast estimate to account for four factors: (1) the O&M forecast estimate assumes no unplanned outage or curtailment-related repair costs, while industry data suggests a 4% outage rate; (2) PG&E has yet to conclude negotiations on its labor contract, so labor costs are uncertain; (3) PG&E has yet to conclude negotiations on its plant maintenance contract, so its plant maintenance costs are uncertain, and (4) the O&M forecast estimate includes escalation based on the Consumer Price Index, which may not reflect actual future inflation. However, with the exception of the outage rate, it is just as likely PG&E's assumptions result in it having overestimated its actual costs as underestimated them. This uncertainty is inherent to the concept of future test year ratemaking, which PG&E proposes and which we generally apply here. This uncertainty can as easily result, in the short-run, in increased shareholder earnings as in unrecovered shareholder costs. It is not cause to adopt a one-way contingency factor.
On the other hand, we are adopting the initial revenue requirement in this proceeding several years in advance of the projects' operation, and without a timely opportunity to update the O&M estimates on the basis of actual plant operation. It appears likely that the timing of PG&E's next GRC will require PG&E to make its showing on updated O&M costs before Colusa is operational, and possibly before either project is operational. Specifically, Humboldt and Colusa are not expected to be operational until May 2009 and May 2010, respectively. PG&E's next GRC test year is 2010; under the typical GRC schedule, PG&E's testimony in that proceeding would be served in December 2008, before the projects' expected operation.15 Under the conventional GRC cycle, the next test year is three years later. Thus, it is possible that the earliest GRC opportunity to update the Humboldt and Colusa O&M costs after their operation will not be until December 2011 for purposes of test year 2013.
In order to address these extenuating circumstances, we therefore adopt TURN's recommendations that we place PG&E's requested O&M contingency amount in a one-way balancing account, which PG&E may recover if and when they are actually expended.16
We authorize PG&E to file an advice letter to adjust the initial revenue requirement for changes to its O&M expense forecast that may occur as a result of (1) increased staffing levels due to permitting requirements, and (2) a change in the commercial operation date, which will change the timing of the O&M expense streams.17 These costs are presumably reasonable. Although allowing these adjustments departs from the concept of future year test year ratemaking, we allow them in recognition of the fact that we adopt the initial revenue requirement in advance of the projects' operation and possibly without the opportunity to update the O&M estimates after operation until GRC test year 2013.
We deny PG&E's request for authority to file an advice letter to adjust the initial revenue requirement for changes to its O&M expense forecast that may occur as a result of deviations from the assumed plant operations. This requested adjustment is redundant of PG&E's requested contingency factor for the possibility of unplanned outages and curtailment-related repair costs, increased inflation, and increased labor and contractual services costs, which we authorize (for recovery in a one-way balancing account) above.
D. Effective Date of Revenue Requirement
The initial revenue requirement for Colusa will begin to accrue in the Utility Generation Balancing Account (UGBA) as of the date of closing of the Colusa PSA, and will be included in rates on January 1 of the following year.
The initial revenue requirement for Humboldt will begin to accrue in the UGBA as of its commercial operation date, and will be included in rates on January of the following year.
E. Other Ratemaking Details
We approve PG&E's unopposed request for authority to recover fuel costs through the ERRA proceeding. This is consistent with our normal ratemaking treatment of fuel costs.
In the event that it is required to finance transmission upgrades related to Humboldt, PG&E requests authority to file an advice letter adjusting the revenue requirement to allow it to collect any difference between the interest rate used to reimburse PG&E for its finance costs and its then-authorized weighted average cost of capital on a pre-tax basis. No party opposed this request. We approve it as reasonable.
9 We grant IEP's motion, filed concurrently with its comments on the proposed decision, to become a party to the proceeding.
10 PG&E suggests that it be permitted to seek this recovery "either in this proceeding or a subsequent proceeding."
11 We reverse the ALJ's earlier ruling sealing the portion of Tr. Vol. 6 addressing this point. D.06-06-066 does not require its confidential treatment, and it is not otherwise entitled to confidential treatment.
12 PG&E cites to D.06-06-035 as adopting a 4.3% contingency for the Contra Costa 8 project, D.05-02-052 as adopting a 5.1% contingency for the Diablo Canyon steam generator replacement project, D.06-07-027 as adopting a 7.4% contingency for its AMI project, and D.05-12-040 as adopting a 20.7% contingency for the Edison steam generator replacement project.
D.06-06-035 (Contra Costa 8) does not discuss this issue, and adopts a settlement which, pursuant to Rule 12.5, does not constitute approval of or precedent regarding this issue.
D.05-02-052 (Diablo Canyon steam generator replacement) does not make reference to either a 15% contingency, which PG&E cites in its testimony, or a 5.1% contingency, which PG&E cites in its comments on the proposed decision. It does make reference to a 2% contingency on one portion of the project (installation contract) and a 20% contingency on another portion of the project (owner's costs). It does not make reference to any contingency amount on any other portion of the project (e.g., procurement contract). In contrast, PG&E here seeks a contingency percentage on total project costs. It is not apparent that D.05-02-052 and its approval of different contingency factors for discrete portions of the nuclear power plant steam generator replacement project is applicable to PG&E's owner's costs for the Humboldt project.
D.06-07-027 (AMI) concerns advanced metering infrastructure, which the decision describes as consisting of metering and communications infrastructure as well as the related computerized systems and software. It is not apparent that D.06-07-027 and its determination of a contingency factor relate to PG&E's owner's costs for the Humboldt project.
In adopting the contingency amount in D.05-12-040 (San Onofre steam generator replacement), the Commission noted the concern in that proceeding that the utilities had underestimated the project costs. It is not apparent that the considerations in D.05-12-040 are applicable to PG&E's owner's costs for the Humboldt project.
13 For example, a comparison of the Colusa PSA capital cost information provided to the Independent Evaluator against PG&E's requested capital costs indicates that, while the PSA cost increased after contract selection, PG&E's owner's costs, including a contingency amount, decreased. No party challenges inclusion of the fixed contract cost in the approved initial capital cost.
14 Specifically, PG&E assumed that Colusa will operate as a load-shaping resource and that Humboldt will operate consistent with a particular engine loading profile.
15 A pending proposed settlement between PG&E and DRA would extend the next test year to 2011; if approved, PG&E's testimony would be served in December 2009, which is after Humboldt's expected operation date but not Colusa's.
16 PG&E does not offer any objection to TURN's proposal either in its rebuttal testimony or in briefs.
17 Although PG&E only requests authority to adjust for a delay in the operation date, we direct it to also adjust the revenue requirement in the event that the plants become operational earlier than assumed.
