3. Discussion
3.1. Introduction
Consistent with the February 1, 2010, Assigned Commissioner's Ruling and Scoping Memo, on March 15, 2010, the parties in the proceeding filed a proposed briefing outline that identified the issues raised in this proceeding and provided a common outline for their consideration. The parties' proposed briefing outline identified the following issues:
· Was PG&E's conduct of the 2008 LTRFO reasonable and consistent with Commission directives?
· Is PG&E seeking authorization of any other projects or contracts, in any other proceeding, pursuant to the authorization granted in D.07-12-052?
· How much of the 800 - 1,200 megawatts which D.07-12-052 authorized should PG&E be allowed to procure in this proceeding? What criteria should be used to determine when, if ever, it would be appropriate for PG&E to procure any remaining megawatts?
· Which of the PPAs and PSA proposed by PG&E are reasonable and in the best interest of PG&E's customers and thus, should be approved by the Commission?
· Should PG&E be authorized to recover costs incurred pursuant to the PPAs in the Energy Revenue Recovery Account (ERRA) and to recover any stranded costs associated with the agreements?
· Should PG&E's rate recovery and initial annual revenue requirement proposals for the Oakley Project, as modified by the Partial Settlement Agreement dated February 17, 2010, be approved?
We address each of these issues below.
3.2. Is PG&E seeking authorization of any other projects or contracts, in any other proceeding, pursuant to the authorization granted in
D.07-12-052?
PG&E asserts that it is not seeking authorization of any other projects or contracts in any other proceeding pursuant to the authorization granted in D.07-12-052. That said, PG&E acknowledges that in D.09-10-017 the Commission approved a Settlement Agreement that provided for 184 MW from the Mariposa Project that fulfilled a portion of the need identified in D.07-12-052.15 PG&E then explains that the GWF Tracy and Los Esteros Critical Energy Facility Upgrade projects proposed in Application (A.) 09-10-022 and A.09-10-034 are not intended to fill the need identified in D.07-12-052 but are instead being proposed on their own merits and as part of an effort to novate several existing California Department of Water Resource (DWR) contracts.16
CARE, PE, TURN and DRA take issue with this contention. CARE notes that "both the GWF Tracy and Los Esteros Critical Energy Facility Upgrades were submitted and evaluated in PG&E's 2008 RFO."17 DRA argues that
D.07-12-052 provided the only legal authority that PG&E had to solicit new resources in 2008 and that this authority was based on Pub. Util. Code § 454.5 which sets forth the LTPP process. DRA asserts that "PG&E could not have issued the LRTFO or solicited DWR for new generation resources, even as part of a novation, without separately obtaining Commission approval to do so prior to the solicitation."18 TURN elaborates on DRA's line of argument where it notes "D.08-11-056 made it clear that the policy favoring novation of the DWR contracts would have to be carried out in a manner consistent with the utilities LTPPs , and did not create some sort of exception to those approved plans."19
PE agrees that the Mariposa project and DWR novations, if approved, should count towards the capacity authorized in D.07-12-052 and identifies various other projects that it believes should also be counted. In this regard, PE first notes that "PG&E has sought approval of new capacity from renewable energy contracts in other proceedings that are above the MW from new renewable energy contracts that was assumed in the LTPP."20 In support of this contention, PE points out that in A.09-02-019, PG&E sought approval of a
500 MW distributed Solar Photovoltaic Program.21 D.10-04-052 addressed that application and adopted a five-year solar photovoltaic program for PG&E to develop up to 500 MWs of solar photovoltaic facilities in the range of 1 to
20 MWs in its service territory. PE goes on to identify other solar projects that PG&E is developing or constructing that have a total capacity of approximately 3,600 MW, far more capacity than D.07-12-052 assumed.22 PG&E responds to PE's assertion that it is developing excess MWs by pointing out that PE's near 3,600 MW figure represents the nameplate capacity of the renewable generating unit rather than the resource adequacy value, which is significantly less because it is intermittent and does not have a high capacity factor.23
PG&E also argues that the GWF Tracy and Los Esteros Critical Energy Facility Upgrade projects proposed in A.09-10-022 and A.09-10-034 are not being sought pursuant to the authorization granted in D.07-12-052, and that it "candidly acknowledged that the upgrade projects are above the authorized LRTFO Need Amount," but states that it believes there are substantial and significant reasons why the Commission should approve the projects.24 Thus, where other parties have argued that the GWF Tracy and Los Esteros Critical Energy Facility Upgrade projects should be counted within the range of MW that PG&E has been authorized to procure, PG&E argues that it should be allowed to procure the latter MW in addition to the maximum amount of MW identified by D.07-12-052. We address this issue here for the sake of consistency with the decision reached in A.09-10-022 and A.09-10-034.
DRA argues that D.07-12-052 provided the only legal authority that PG&E had to solicit new resources in 2008 and that this authority was based on Public Utilities Code Section 454.5 which sets forth the LTPP process. DRA asserts that PG&E could not have issued the LTRFO or solicited DWR for new generation resources without separately obtaining Commission approval to do so.25
PG&E disputes DRA's claim that the LTPP is the only legal authority it had to solicit new resources. PG&E argues that "the DWR Novation Decision did not preclude the utilities from including new generation resources in a novation transaction ... ."26 Thus, PG&E appears to argue that the fact that the novation decisions do not preclude it from including generation resources somehow grants it authority to procure resources above the authorized LTRFO need amount. Ultimately, PG&E offers no authority for the proposition that its removal of the GWF Tracy and Los Esteros Critical Energy Facility Upgrade projects from the LTRFO proceeding in which they were developed, and inclusion in the novation proceeding, somehow grants PG&E authority to procure additional resources beyond, or as PG&E phrases it, "outside" those allotted PG&E in D.07-12-052. We therefore, reject this argument.
PG&E further argues that "... parties are always free to propose to the Commission transactions that are beneficial for customers."27 In its Reply Testimony in the consolidated proceeding considering A.09-10-022 and
A.09-10-034, PG&E urged approval of these contracts so as to mitigate the risk of project delay or failure.28 However, as TURN notes, "this Commission has already considered and rejected in its LTPP policy decision the very same proposal that PG&E offers now."29
Ultimately, PG&E fails to identify any authority that allows it to procure MW in excess of those allotted in its LTPP.30 We agree with DRA that the LTPP was the appropriate legal authority that PG&E had to solicit new resources in 2008 and that this authority was based on Public Utilities Code Section 454.5 which sets forth the LTPP process. As a general rule, to support decisional consistency and discourage the parsing of projects into different applications as a means to circumvent our rulings, to the extent that procurement is allowed outside of the proceeding to approve the agreements that are within the utility's previously authorized procurement authority, any approved MW should be counted against the authorized procurement. Consistent with this general rule, absent a specific exemption providing for a deviation from the previously authorized procurement authority, Commission approved projects that allow utilities to procure new generation during the time-frame covered by their LTPPs will count toward the authorization granted in the LTPP.
3.3. Was PG&E's conduct of the 2008 LTRFO reasonable and consistent with Commission directives?
PG&E asserts that its RFO process complied with the procedural requirements of D.07-12-052.31 In support of this assertion PG&E provides a table and discussion of the Procurement Review Group (PRG) and/or Cost Allocation Mechanism (CAM) Group meetings and emails that it distributed related to the 2008 LTRFOs.32 PG&E also notes that an independent evaluator (IE) was actively involved in each phase of the RFO process, as dictated by Ordering Paragraph 9 of D.07-12-052, and includes the report of the IE as an appendix to its testimony.33 Finally, PG&E provides a lengthy discussion of its evaluation of the 2008 RFO responses. PG&E divides its evaluation of the 2008 RFO responses into three phases.
Prior to reviewing the submitted projects, a team of subject matter experts, including experts from within PG&E, the independent evaluator, Energy Division, and members of the PRG, developed a list of criteria by which projects would be evaluated.34 The evaluation criteria included the following eight areas:
· Market Valuation - comparison of an offer's costs, as reflected in its pricing and unit specific features, to its benefits from a market perspective.
· Portfolio Fit - a metric that differentiates offers by the flexibility and firmness of their energy delivery, energy delivery patterns, geographic location, and the qualification for local resources.
· Credit - a score based upon the participant's credit worthiness and its willingness to post collateral.
· Participant Qualification - examination of the developer, contractor, and operations and maintenance experience associated with the project.
· Project Viability - focuses on project development (including environmental permitting), project construction, and financing to consider the likelihood of a project being permitted and developed, the feasibility of the proposed construction schedule and costs, and the adequacy of financing during construction and operation of the project.
· Technical Reliability - evaluates expected project construction (combustion turbines, internal combustion engines, heat recovery steam generators, heat sink), project performance (heat rate and capacity estimates, availability guarantees, unplanned outage factor guarantee, fixed and variable Operation and Maintenance (O&M), and start-up costs), and project operations (staff training, staffing requirements, maintenance support availability, permit limitations, service agreement terms, maintenance outage requirements, spare pats and labor agreements).
· Environmental Leadership - evaluates projects based on their ability to assist PG&E in meeting some of its specific goals, such as fostering development and deployment of clean and sustainable energy supply resources, or continuing to partner with and support PG&E's customers and communities.
· Conformance with PG&E's Non-Price Terms and Conditions - assessment of the extent to which an offer altered the allocation of benefits, burdens, and risks under the form PPA and PSA.
These criteria were given initial ranges within which the scores would fall. Rather than being weighed equally, these eight criteria were given vastly different weights. The final weights were determined based on the bids submitted using a predetermined methodology.35 The final weighted criteria were use to calculate a "G-score"36 which was initially used to rank the offers.37
After the initial G-score rankings were established for the offers, PG&E, with input from the independent evaluator, PRG, and CAM group, considered "exceptional project-specific information" that allowed an offer to be given a reduced rank or even eliminated from consideration.38 After this re-ranking, certain projects were moved to a "shortlist."39 PG&E does not provide a clear explanation why 15 projects with higher G-scores than the worse project on the shortlist were excluded from further consideration.40
After the shortlist was developed, PG&E and the IE met with each participant whose offer was on the shortlist to review the offer and receive any updates to the project. Based on these discussions, PG&E prioritized the shortlisted projects into high, middle, and low tiers for negotiations. PG&E placed projects on these tiers based on consideration of a combination of each shortlisted offer's market value, degree of compliance with the form PPA or PSA, project viability, seller concentration, geographic concentration, and expected timely completion of negotiations.
In D.07-12-052 this Commission stated, "[a]n open, transparent and competitive procurement process is the king-pin to a successful hybrid market, and that theme, in tandem with environmental issues, guides our decision on the 2006 LTPPs."41 Consistent with this statement, D.07-12-052 established specific substantive and procedural requirements for PG&E's RFO process.42
The record of the proceeding shows that PG&E involved the IE, and PRG in several aspects of the RFO as required by D.07-12-052.43 Though we generally feel the RFO functioned well, as with any new process, there were minor shortcomings. There were instances were PG&E made decisions for which it provided little or no explanation or rationale. For example, PG&E states that after the initial G-score rankings were established for the offers, "exceptional project-specific information" was considered that allowed an offer to be given a reduced rank or even eliminated from consideration.44 Though it gives an example of how exceptional project-specific information could be used, PG&E provides no information or guidance as to what, if any, "exceptional
project-specific information" was actually considered and where. PG&E's lack of clarity can also be seen where projects were moved to the shortlist.45 Again, it is not immediately clear what the criterion was to get onto the shortlist. In particular, PG&E's explanation of why several projects with higher G-scores than the worst project on the shortlist were excluded from further consideration is unclear. While we conclude that PG&E's process was, for the most part, open and transparent and in most regards complied with D.07-12-052, we encourage PG&E to take concrete steps to improve its presentation of the process. In particular, we encourage PG&E to continue working with the PRG and CAM groups, and to make the materials produced in these groups a part of the proceeding record in future RFOs. Additionally, PG&E should provide greater details of when and how discretionary decisions where made, and how these decisions effected the scoring and selection processes.
Though we find that PG&E reasonably conducted the RFO, the weights placed on certain criteria do not fully reflect this Commission's stated priorities. As noted by the IE, "the portfolio fit evaluation element might have too great a weighting in the development of an offer's total evaluation score, particularly because the quantitative market valuation and transmission cost estimates capture key portfolio fit attributes."46 In contrast, of the eight factors that PG&E weighted to compute its G-score, "environmental leadership" was given 1/25th the weight of PG&E's highest weighted factor and the lowest overall weight of all the factors. PG&E's low weighting of environmental leadership may have been exacerbated by PG&E's inclusion of a broad range of ill-defined activities under this heading (which can produce a uniform cluster of scores), and PG&E's "after the fact" decision to reduce the weight of any scores that clustered together. We therefore, conclude that PG&E's criteria weighing was not balanced so as to best reflect the priorities we established in D.07-12-052.
In light of the conclusions above, we find that while PG&E properly solicited offers and generally acted in a manner consistent with our guidelines and expectations for the LTRFO process, PG&E could and should have provided greater transparency in the evaluation process and more accurately reflected the Commission's stated priorities by giving greater weight to environmental factors and enhancing definitions related to environmental scoring. These criticisms should be taken in the context of the RFO as a whole and while significant, particularly in regard to future RFO's, do not change our determination that overall PG&E conducted a reasonable RFO and evaluation.
CBE argues that because PG&E failed to submit a Proponent's Environmental Assessment (PEA) as required by CEQA as part of its 2008 LTRFO, its conduct was neither reasonable nor consistent with Commission directives. In particular, according to CBE, "Commission Rule 2.4 mandates that PG&E include with its application either a PEA or an explanation of the exemptions it believes apply."47 CBE further argues that PG&E's contention that the approval sought is not a project for CEQA purposes wrongly attempts to expand one of the CEQA exemptions.48 PG&E responds that these arguments are unfounded. As PG&E notes, two of the four contracts at issue are with the developers of proposed power plants who are subject to the jurisdiction of the CEC, while the other two proposed PPAs are not projects within the meaning of CEQA because the plants will continue to operate subject to existing permit limits, with no physical modifications proposed.49
We agree with PG&E that CEQA Guidelines, the applicable case law, and our past practices make clear that review by the Commission of these proposed contracts, which will be (or have been) environmentally evaluated by the CEC and other agencies, does not trigger CEQA for this application.
On April 1, 2009, PG&E filed an application seeking an expedited order approving a PPA with Mariposa Energy, LLC. D.09-10-017 adopted an all party settlement and approved the PPA.50 In D.09-10-017 we found that with regard to its 2008 LTRFO, "PG&E conducted an open, competitive and fair solicitation and contract selection process."51
Because the application underlying D.09-10-017 sought an expedited order approving the Mariposa Energy Center only the finding above was based on a far more limited record than is currently before us. Here PG&E has provided us much more detailed information about its solicitation and bid selection process than it did in D.09-10-017. We now have before us six volumes of testimony (some of which by themselves are more than twice as large as PG&E's testimony in D.09-10-017), and more than 35 exhibits. In contrast, the exhibit list in
D.09-10-017 identifies only one document (and its confidential version). In addition, where D.09-10-017 reviewed an all party settlement, here five parties oppose PG&E's application and three others support it. Thus, the record developed by the parties in this proceeding presents issues that were not developed in PG&E's prior application where there was neither cause nor opportunity to compare the Mariposa Energy Center to other potential projects.
Though we previously identified points where PG&E could improve the next RFO process, many of the problems we identify in this proceeding relate to project ranking and cannot be seen where a single project is presented for approval. Therefore, to the extent that we previously found that PG&E "conducted an open, competitive and fair solicitation and contract selection process," this finding should be applied to PG&E's selection of the Mariposa Energy Center only.
3.4. How much of the 800 - 1,200 megawatts which D.07-12-052 authorized should PG&E be allowed to procure in this proceeding? What criteria should be used to determine when, if ever, it would be appropriate for PG&E to procure any remaining megawatts?
Parties are predictably split on the first of this two-part question. For the most part the parties agree that D.07-12-052 authorized PG&E to procure
800 - 1,200 MW; that because two projects from PG&E's 2004 RFO were terminated, PG&E's procurement authority increased by 312 MW to between 1,112 and 1,512 MW; and that the 184 MW associated with the Mariposa project (D.09-10-017) reduce PG&E's range to 928 - 1328 MW.52 CUE, CURE, IEP, and PG&E argue that the Commission should approve the contracts allowing PG&E to procure the maximum amount of generation.53 In general, CARE, DRA, TURN and PE assert that PG&E's position relies on data that has been shown to be incorrect. Thus, CARE, DRA, and TURN assert the Commission only should approve contracts allowing PG&E to procure generation at the minimum of the established range. For its part, PE and CBE argue that PG&E should not be allowed any new generation.
3.4.1. Compliance with Commission-Mandated Planning Reserve Margin (PRM) Requirements
PG&E, CURE, and CUE argue that given uncertainties associated with new generation resource development, procuring the high end of the MW range is prudent as it will ensure that PG&E will not be out-of-compliance with Commission-mandated PRM requirements.54 CARE and PE dispute this contention and note that where the Commission requires PG&E to maintain a 15-17% reserve margin, in summer 2009 the actual reserve margin for PG&E's NP26 territory never dropped below 44%.55 Additionally, CARE notes that "[a]ccording to the CAL-ISO 2009 Summer Assessment PG&E currently enjoys a 30.6% Planning Reserve Margin,"56 and that this Commission addressed resource uncertainty in D.07-12-052 when it established PG&E's procurement range.57
CARE and PE go on to identify two reports that they assert reinforce their conclusion that there is no risk of a supply shortage. First, the CEC staff issued a report in October 2008 which states unequivocally that D.07-12-052 "over estimated the amount of capacity flowing North to South on Path 26 during PG&E peak demand periods by at least 1,900 MW."58 On the basis of the CEC staff report, CARE and PE argue that PG&E has no need to procure from 1,112 MW to 1,512 MW of new capacity, and certainly no need to procure more capacity than authorized by D.07-12-052 in order to hedge the risk of project delay and failure. The second report cited by CARE and PE is the report adopted by the CEC on December 2, 2009, titled The California Energy Demand 2010-2020 Adopted Forecast (hereafter, the "2009 Forecast"). The 2009 Forecast, when compared to the 2007 Forecast that was relied upon in D.07-12-052, shows the CEC has reduced its forecast of peak demand in PG&E's planning area in 2015 by 597 MW.59 The CEC attributes the drop in forecasted demand to lower economic growth and increased energy efficiency.
In its reply comments, PG&E challenges the report on which PE relies. According to PG&E the power flows on Path 26 used in the CEC Staff Report cited by these parties reflected a period of generation surplus in California, and is not informative of the support Northern California provides Southern California under stress conditions.
We agree with PG&E (as well as the CEC Report itself) that the Planning Reserve Margin Proceeding (Rulemaking (R.) 08-06-012) is the appropriate place to fully address issues related to the reserve margin.60 However, we also acknowledge that the CEC's report reflects less need than previously determined.
PG&E and in particular CUE/CURE, argue that the potential for project failure must also be taken into consideration. According to CUE/CURE "[b]igger than any adjustments at the margin of any analysis of need is the potential for an additional major project already procured to fail to materialize."61 By way of example, PG&E and CUE/CURE identify the Russell City project, a 600 MW gas-fired facility proposed for Alameda, as a potential issue. According to CUE/CURE, "[i]f the Russell City project ultimately fails ... that will increase the authorized MW need for PG&E by some 600 MW to 1,528 - 1,928 MW."62
While we acknowledge that a potential failure of the Russell City project could have an impact on PG&E's procurement, we do not believe it appropriate to weigh this factor in our deliberations here. In addition to the project's failure being wholly speculative at this time,63 we note that should the project fail, the terms of D.07-12-052 allow PG&E to procure generation in an offsetting amount.
We relied on the 2007 draft forecast in D.07-12-052 because it was the "most current public information available" and therefore provided "a better `snapshot' of the current needs of the system."64 However, the CEC 2009 IEPR found the 2007 California Energy Demand (CED) forecasted need determination to be "markedly" higher than actual need.65 No party in this proceeding genuinely disputes that the CEC's 2009 IEPR forecast of peak demand for the PG&E service area in 2015 is less than in the 2007 CEC forecast relied upon in D.07-12-052. Rather, the parties primarily disagree about the degree and impact of the difference between the two forecasts. Both CARE and TURN note that in its reply testimony, PG&E calculates that the 2009 CED forecast MW reduces PG&E need in its service territory by 300 MW by 2015.66
PG&E first attempts to minimize the import of this reduction by noting that it amounts to only 1.4% of peak demand and asserting that the reduction may be negated if the CEC's calculations are wrong. PG&E then concludes that basing a need assessment on short-term trends is imprudent when considering long-term resource additions. PG&E's argument asks us to ignore actual error because of the possibility of further errors, which are as likely to offset the reduction in demand as they are to increase it. We are not persuaded by PG&E's arguments.
Even when viewed as a portion of peak demand, we do not believe
300 MW is insignificant. PG&E appears to agree with us on this point in as much as it (along with CUE/CURE) has consistently argued that 312 MW should be added to the range set forth in D.07-12-052 due to the cancellation of previously approved projects.67
Finally, while we agree that basing a need assessment on short-term trends is imprudent when considering long-term resource additions, we are not engaging in such an exercise here. While we sincerely hope that California's economic downturn is a short-term trend, as noted in the Assigned Commissioner's Ruling and Scoping Memo, rather than undertake a new need assessment and create unnecessary regulatory uncertainty in this proceeding, we are determining what amount of procurement we should allow, within the established range.
Based on information supplied to the Commission by the CED, in D.07-12-052 we assumed that PG&E would export 3,000 MW of electricity to Southern California.68 PE, CARE, TURN, and DRA point out that after the release of the 2006 LTPP, the CEC found that PG&E's exports were overestimated by
"at least 1,900 MW."
Rather than rebut the accuracy of these calculations, PG&E challenges the validity of the CEC report on claims that "the power flows on Path 26 used in the CEC Staff Report [cited by TURN, DRA, Pacific Environment and CARE] reflected a period of generation surplus in California, and is not informative of the support Northern California provides Southern California under stress conditions."69 However, PG&E's testimony in this regard is both conclusory and limited. The testimony lacks either data or supporting citation that might allow us to ascertain the veracity of the statement as well as the impact of the claimed "period of generation surplus". Indeed, rather than assert that the study's criticism of our previous assumption (of 3,000 MW flow from Northern to Southern California) is wholly without merit, PG&E acknowledges that imports by non-CAISO parties (who presumably had or created the purported generation surplus) is only one of several factors that impact power flows in either direction on Path 26.70 Thus, even if we accept that a period of generation surplus rather than stress was examined in the more recent study, PG&E's testimony does not assert, and we are unable to conclude, that the study's criticism of our previous assumption (of 3,000 MW flow from Northern to Southern California) is wholly without merit.
PE and CARE also argue that the lower end of the range established in D.07-12-052 is appropriate because energy efficiency has had a larger effect on consumption than previously anticipated. In particular, PE argues that "need in PG&E's territory has been reduced by approximately an additional 2,600 gigawatt/hours (GWh) from the 2009 CED forecast levels due to additional incremental energy efficiency impacts."71 CARE notes that, in addition to the aforementioned report, in January of 2010 the CEC developed a report on The Incremental Impacts of Energy Policy Initiatives Relative to the 2009 Integrated Energy Policy Report. CARE contends that the latter report estimates that "the incremental impacts of prospective CPUC 2008 Energy Efficiency Goals programs in the PG&E service territory would amount to 506 MW to 795 MW of Peak Demand Savings by the year 2015."72
PG&E acknowledges that it is true that the 2009 CEC demand forecast includes more energy efficiency savings than the 2007 CEC forecast, but argues that PE is double-counting the increase in energy efficiency included in the new CEC peak demand forecast. According to PG&E, because the 2009 CEC demand forecast includes energy efficiency savings, using it and counting incremental energy efficiency effectively double counts the incremental energy efficiency.73 While PG&E makes a valid point, we do not agree that the full impact of the energy efficiency goals we have approved since D.07-12-052 are fully incorporated in the 2009 CEC forecast. We will evaluate the proper counting of incremental energy efficiency as part of the need for new capacity in R.10-05-006.
After arguing that PG&E should only be allowed procurement at the lower end of the range established in D.07-12-052, TURN asserts that "[t]he criteria that should be used to determine when, if ever, it would be appropriate for PG&E to procure any "remaining megawatts" will be determined in the 2010 LTPP proceeding, and need not be addressed here." PE reaches a similar conclusion based on PG&E's current reserve margins.74 Though PG&E acknowledges that once-through-cooling (OTC) issues can be addressed in the 2010 LTPP and still result in the replacement of the Moss Landing and Pittsburg facilities by the 2017 deadline,75 PG&E believes that this approach is fundamentally flawed and will result in uncertainty, risk, and decreased reliability.
We believe PG&E overstates its concerns in this regard. As we have previously noted, retirements can be delayed should the need arise. While PG&E previously acknowledged that it plans more retirements than anticipated in D.07-12-052, it appears to ignore the role delaying retirements can play in offsetting unexpected need.
PG&E notes that D.07-12-052's need determination included an assumption that 4,200 MW of aging units would retire by 2015 and argues that the California State Water Board (SWB) has moved the deadline to retrofit, repower, or retire all of the aging natural gas-fired units using OTC technology to 2017. As PG&E states, "there is nothing in the SWB draft report that indicates that these aging and inefficient units should not be retired earlier if possible."76 Moreover, because the OTC units impacted by the SWB deadlines account for approximately 5,600 MW of aging facilities, PG&E, CUE and CURE interpret the new deadline as meaning that the "current expectations are for more retirements than assumed in the LTPP decision."77
In contrast, TURN asserts that the aging plant retirement schedule in D.07-12-052, which assumed 4,200 MW would be retired by 2015, no longer appears accurate since the SWB's November 2009 draft OTC policy now calls for the Moss Landing and Pittsburg facilities (totaling over 2,800 MW) to be retired by December 2017.78 PE agrees with TURN and asserts that even if the prior retirement assumptions had proven accurate, no additional MW need to be allocated because many existing OTC facilities are currently running far below capacity.79
Both of the positions taken appear to have merit; it appears that more OTC units than originally contemplated may be effected by the SWB's decision and that PG&E will have until 2017 rather than 2015 to retire various OTC units. Given these developments we are not, at this junction, inclined to weigh this factor for or against procurement at either end of the range established in D.07-12-052.
3.4.7. The Need for Conventional Generation to Integrate Renewable Resources
PE takes issue with PG&E's claim that the requested contracts are necessary to integrate renewable energy sources into the grid.80 In particular, PE argues "that new natural gas facilities are not currently needed to integrate renewable energy and meet RPS goals."81 PG&E does not address this argument.
Instead, PG&E argues the far broader point that conventional generation resources are needed to integrate renewable energy that will be coming on-line in the next few years.82 Perhaps as a result of this `missed connection' the parties fundamentally disagree about the meaning of the evidence they both cite. By way of example, both parties identify particular sections of the CEC report that support their position.83
Given these considerations, we are not, at this junction, inclined to weigh this factor for or against procurement at either end of the range established in D.07-12-052.
CARE, DRA, TURN and PE present ample evidence that our prior range was based on faulty data in support of the position that procurement should only be allowed at the lower end of the range established in D.07-120-52. PG&E and CUE/CURE generally respond that these parties present an incomplete view of the data and wrongly attempt to relitigate issues decided in D.07-12-052.
On balance, given our concurrence with CARE, DRA, TURN, and PE in Sections 3.4.1, 3.4.2, 3.4.3, and 3.4.4 above, we believe it is most appropriate to only allow PG&E to procure resources at the lower end of the range established in D.07-12-052. However, because we also find merit in PG&E's assertions in Sections 3.4.6 and 3.4.7 herein, rather than limit PG&E's procurement to the bottom of the range established in D.07-12-052, we determine that PG&E should procure between 950 - 1000 MW of new generation resources.
3.5. Which of the PPAs and PSA proposed by PG&E are reasonable and in the best interest of PG&E's customers and thus, should be approved by the Commission?
For the most part, the parties distribute themselves at three equidistant points on this issue. At one end, PG&E, IEP and CUE/CURE assert that all the proposed PPAs and PSAs should be approved as reasonable and in the best interest of PG&E's customers. For the reasons stated above, we reject the contention that PG&E should be allowed to procure at the maximum of the range established in D.07-12-052. TURN and DRA occupy the middle ground on claims that, given various changed circumstances, only those projects that can be combined to provide the minimum number of MW authorized in D.07-12-052 should be approved. While we understand the reasoning behind TURN's and DRA's position, we believe it is constrained by the belief that we must select projects that yield a number of MW from among the projects PG&E has chosen to present in this proceeding. No party in this proceeding has identified or argued that there is a decision or rule of law that would narrow our discretion in this manner. At the other end of the continuum CARE argues that, given the changed circumstances, few if any of the PSAs or PPAs should be approved as they are neither reasonable nor in the best interest of PG&E's customers, while CBE and PE argue that none of the projects should be approved. We discuss each project below.
We appreciate PG&E's presenting this project again, in the context of all projects considered under the LTRFO process. As we approved this PPA in D.09-10-017 and have already included it in our revised calculation of PG&E's range of need, we need not revisit it again here.
The Marsh Landing Project will be located north of Antioch, California on a brownfield site next to Mirant's existing Contra Costa power plant. The project will consist of four combustion turbines with a combined output of 719 MW under July peak conditions and is expected to be on-line by May 2013.
The Marsh Landing PPA has a number of important benefits for PG&E's customers. First, the Marsh Landing Project will be a new peaking facility that will respond to PG&E's peak load requirements and allow for the integration of intermittent renewable resources.84 Second, the project will provide the Bay Area resource adequacy (RA) capacity and be a reliable new generation resource. Third, the project has one of the best market valuations of all the offers received in PG&E's 2008 LTRFO, which will help ensure that PG&E customers receive energy and capacity at just and reasonable prices.85 Finally, the project is operationally flexible and capable of providing CAISO ancillary services.86
CARE asserts that the Marsh Landing project should not go forward because is lacks the type of operating flexibility favored in D.07-12-052. In particular CARE argues that while the Marsh Landing project has the quick starting capability that is needed to back up intermittent renewable resources, the facilities' maximum number of starts per year is limited to 167 per turbine, and the annual hours of operation are limited to 1,705.87 Though PG&E claims to have taken these considerations into account in its evaluation, CARE disputes this claim. CARE is the only one of the active parties that specifically opposes the Marsh Landing Project.88
PG&E proposes to execute a short-term PPA with Mirant for the existing Contra Costa 6 & 7 units. This PPA is a tolling agreement for the 674 MW output from units 6 & 7 running from November 1, 2011, through April 30, 2013, when the Marsh Landing Project is scheduled to come on-line. PG&E states that, assuming all necessary regulatory and governmental approvals are received, units 6 & 7 would then be retired in April 2013.89
In its brief PG&E asserts that, in addition to ensuring that two aging and inefficient facilities that utilize OTC technology are permanently shut down, the PPA for units 6 & 7 has a number of customer benefits.90 Until adequate capacity from new resources comes on-line in PG&E's service area, the units will provide important and valuable attributes, such as Bay Area RA capacity, at a reasonable price.91 Also, retirement of older, inefficient units such as these is consistent with California policy aims, including the reduction of OTC and GHG. Finally, retirement of these units will reduce transmission costs for both the Marsh Landing and Oakley Projects by freeing-up transmission capacity.92 PG&E goes on to explain that it and Mirant Delta negotiated a new tolling agreement for units 6 & 7 beginning November 1, 2011, and ending April 30, 2013, without reference to the Marsh Landing Project.
The proposed Oakley Project will consist of two GE 7FA.05 gas turbines, two heat recovery steam generators, and one steam turbine producing 586 MW under July peak conditions. The Oakley Project has a guaranteed commercial availability date of June 2014.
PG&E asserts that the Oakley Project will benefit its customers first in that the turbines used will result in it having one of the lowest heat rates, and most flexible operating capabilities for a combined cycle facility in California. This project would also provide Bay Area RA capacity. The Oakley Project also has one of the best market valuations of all of the offers received in PG&E's 2008 LTRFO.93 Finally, like the Marsh Landing Project, the Oakley Project is operationally flexible and capable of providing a number of CAISO ancillary services.94
TURN questions PG&E's valuation of the Oakley Project. As TURN notes, "the 30-year life of the Oakley Project (compared to 10 years for the PPAs) introduces a much greater level of uncertainty into the analysis of the resource's levelized value."95
Though PG&E presents the Oakley Project as a flexible fast ramping facility, CARE points to information found in PG&E's confidential evaluation of the project that calls this assertion into question. CARE further argues that because it is limited to less than one start a day, the Oakley Project does not comply with our directive in D.07-12-052 that the utilities "procure dispatchable ramping resources that can be adjusted for the morning and evening ramps created by the intermittent types of renewable resources."96 CARE also notes an apparent discrepancy in the heat rate PG&E has claimed for the project related to differences in the heat rate of the project at minimum load and higher levels of output.97 Lastly, CARE states that problems have been identified with the location for the project.98
The Midway Sunset Project is an existing natural gas-fired cogeneration facility located in Kern County, California. Steam from the facility is used in oil field operations located near the plant. Under the Midway Sunset PPA, PG&E will purchase 129 MW produced from two units at the facility for the first five years of the agreement, and 61 MW from one unit through the remainder of the term (until September 30, 2016).99 Under the PPA, Midway Sunset has guaranteed a heat rate to ensure low GHG emissions.100 This project received the highest environmental policy rating of any project in the 2008 LTRFO that PG&E recommended.101 Since the Midway Sunset Project is already on-line, no additional transmission upgrades are necessary. In addition to the above benefits, this project furthers the Commission's policy of encouraging QFs to participate in utility solicitations and is consistent Commission directives to retain existing QF capacity.
Given the discussion immediately above and in Sections 3.3, and 3.4 within, particularly the determination of need in Section 3.4.8, we approve the Marsh Landing, the Contra Costa 6 & 7, and Midway Sunset PPAs. While all the projects proposed in this proceeding have attributes desirable for renewable integration and offer numerous environmental benefits relative to many generating resources currently operating as part of PG&E's Resource Adequacy Portfolio, the Marsh Landing, the Contra Costa 6 & 7, and Midway Sunset PPAs best reflect the Commission's environmental priorities stated in D.07-12-052 and the current need determination detailed in Section 3.4.8 above. Therefore, we find that Marsh Landing, the Contra Costa 6 & 7, and Midway Sunset PPAs are reasonable and in the public interest as they provide sufficient MW to ensure safety and reliability at a fair price. Though we do not find CARE's dispute regarding the heat rate of the Oakley Project persuasive, combining the need determination, the outstanding concerns raised by both TURN and CARE, it is appropriate, at this time, to deny the Oakley Project. Combined, the approved projects allow PG&E to procure a total of 719 MW of new capacity.
Our calculation of this amount does not take into account the MW produced by Contra Costa 6 & 7 or Midway Sunset because these are existing plants that do not represent new system resources. However, the contracts with Contra Costa 6 & 7 and Midway Sunset will count against PG&E's bundled procurement plan. Our approval of the Marsh Landing Project and the Contra Costa 6 & 7 PPA is conditioned on PG&E's and the Mirant Corporation's agreement to undertake all necessary and appropriate activities to obtain the necessary permits and approvals to retire Contra Costa 6 & 7 as scheduled, on April 30, 2013, or when the Marsh Landing Project becomes operational, whichever comes first.
Though we deny the Oakley Project at this time, we understand that developing and building a power plant in California is a long process, fraught with pitfalls. Given this risk and the fact that we believe this plant has numerous beneficial attributes, PG&E may resubmit the Oakley Project, via application, for Commission consideration under the specific conditions below. All of these conditions are contingent on PG&E being able to demonstrate that the Oakley Project has received the necessary permits as evidence that future delays or obstacles for this project are minimized. Prior to the next PG&E LTRFO the conditions under which PG&E may resubmit the Oakley Project are, if,:
1) Another, approved project or projects fail, creating an open need such that the total capacity of all projects approved in this decision, other decisions approving capacity that the Commission determines should be counted towards PG&E authorized procurement, and the total net capacity difference102 do not sum to greater than the midpoint of the total range, currently 1128 MW,
2) If PG&E is able to retire an OTC plant (other than Contra Costa 6 & 7) of comparable size, at least 3 years ahead of schedule, or
3) If the final results from the CAISO Renewable Integration Study demonstrates that, even with the projects approved by the Commission, there are significant negative reliability risks from integrating a 33% Renewable Portfolio Standard.
These criteria are consistent with the Commission's stated environmental and procurement objectives, and our goal of maintaining high levels of reliability for ratepayers.
At this point we decline to count the 500 MW of solar photovoltaic facilities we recently authorized PG&E to procure in D.10-04-052, toward its current procurement allotment. The size and nature of this project, in conjunction with concerns related to the need for generation to back up intermittent generation, raise issues that cannot be resolved on the record before us and which, in any event, are better addressed in the context of the next LTPP.
In that we have only allowed PG&E to procure 719 MW in this proceeding but previously determined that PG&E should be allowed to procure 950 - 1000 MW of new generation, PG&E has authority to procure between 231 - 281 MW in new generation pursuant to its current LTPP. However, except as noted previously in this section, PG&E shall not procure new generation in excess of the total 950 - 1000 MW we have identified as appropriate while under its current LTPP.
D.07-12-052 requires IOUs to demonstrate how each application for new fossil generation fits into the IOU's GHG reduction strategy.103 PG&E states the Marsh Landing Project consist of four Siemens STG6-5000F combustion turbine units, which are generally intended for peaking purposes and anticipated to run at substantially less than a 60 percent annualized capacity factor. PG&E therefore, concludes that the Marsh Landing Project is not subject to the Emissions Performance Standards (EPS).104 PG&E further notes that the Marsh Landing Project will be operationally flexible in support of PG&E's effort to integrate intermittent renewable generation and thereby enable an overall reduction in GHG emissions from PG&E's portfolio.105
Similarly, Contra Costa 6 & 7 is not expected to impact PG&E's GHG emissions because it is an existing generating facility and the plants will continue to operate subject to existing permit limits, with no physical modifications proposed.106 Moreover, EPS does not apply to Contra Costa 6 & 7 because the agreement is for less than five years.
Finally, because the Midway Sunset project represents a seven year PPA with a specified resource with no system purchases it resolves the first Senate Bill (SB) 1368 requirement. The second requirement (an annualized capacity factor of 60 percent or greater) is satisfied because the Midway Sunset project is a cogeneration/combined heat and power facility that is anticipated to have emissions rates less than 1,100 lbs/MWh.
3.6. Should PG&E be authorized to recover costs incurred pursuant to the PPAs in the Energy Revenue Recovery Account (ERRA) and to recover any stranded costs associated with the agreements?
PG&E asserts that Commission policy favors allowing recovery in rates, through the ERRA balancing account, of costs associated with the Marsh Landing, Contra Costa 6 & 7, and Midway Sunset PPAs.107 To the extent that any of the contracts are approved by the Commission, no party appears to dispute recovery of any stranded costs associated with the agreements through the ERRA.
3.7. Should PG&E's rate recovery and initial annual revenue requirement proposals, as modified by the Partial Settlement Agreement dated
February 17, 2010, be approved?
On February 9, 2010, PG&E filed and served a notice of settlement conference for February 16, 2010, to discuss a settlement in principle between and among PG&E, TURN, CURE, CUE, and DRA (collectively, "Joint Parties"). On February 17, 2010, the Joint Parties filed a motion for acceptance of a Partial Settlement Agreement. Pursuant to Rule 12.2, on March 9, 2010, CARE and PE filed comments opposing the Partial Settlement Agreement. On March 24, 2010, the parties notified Administrative Law Judge (ALJ) Farrar that they had agreed that hearings to address the motion for acceptance of the Partial Settlement Agreement would not be necessary.
The Partial Settlement Agreement is attached to this decision as Appendix A. By its terms, the Partial Settlement Agreement addresses the ratemaking issues and cost recovery in the 2008 LTRFO proceeding, but does not address selection of projects to meet the LTRFO need amount. Under the terms of the Partial Settlement Agreement, the Joint Parties reserved their rights to advocate for Commission approval of all or a portion of the projects in PG&E's 2008 LTRFO application. The Partial Settlement Agreement only applies to the applicable ratemaking and cost recovery treatment for the projects selected by the Commission in this decision.
Essentially there are three ratemaking and cost recovery components to the Partial Settlement Agreement. First, the Partial Settlement Agreement provides that PG&E shall recover the costs of all payments made pursuant to the Mirant Marsh Landing PPA, Contra Costa 6 & 7 Tolling PPA, and Midway Sunset PPA through PG&E's ERRA. Second, with regard to the Oakley Project, the Joint Parties agreed that the cost recovery and ratemaking proposals applicable to the Oakley Project, as modified by the Partial Settlement Agreement, are reasonable and should be approved by the Commission, if Oakley is selected to meet the LTRFO need.108 Third, pursuant to the Partial Settlement Agreement, the Joint Parties agreed that, in lieu of recovering stranded costs through a non-by-passable charge pursuant to
D.04-12-048 and D.08-09-012, a "Net Capacity Cost Charge" authorized under
SB 695 and Section 365.1, will apply to the Mirant Marsh Landing PPA and Oakley Projects. The methodology in the Partial Settlement Agreement incorporates the Joint Parties' proposal (approved by the Commission in D.07-09-044, Appendix A, Section IX), for use prior to completion of an energy auction.109
3.7.2. Arguments in Favor of the Partial Settlement Agreement
The Commission will approve a settlement if it finds the settlement "reasonable in light of the whole record, consistent with law, and in the public interest."110 Joint Parties assert that the Partial Settlement Agreement is reasonable in light of the whole record. Joint Parties note that they reached settlement only after PG&E served its opening testimony and the parties conducted discovery about PG&E's ratemaking proposals.111 As a result of settlement discussions, PG&E agreed to reduce its initial capital cost estimate, cap the O&M costs and capital addition costs to the estimated costs used in the evaluation process for a period of eight years, and provide detailed plant availability and heat rate information for the facilities at issue here and for other PG&E owned facilities. Joint Parties also assert that PG&E's proposal for recovery of net capacity costs is also reasonable in light of the whole record because the project(s) we approve herein are needed to provide reliable electric service and recovery of these costs through a net capacity cost charge is fully supported by the recently enacted SB 695.
Joint Parties next assert that the Partial Settlement Agreement is fully consistent with the law and existing Commission precedent. Specifically, Joint Parties assert that recovery of PPA costs through ERRA is a well established practice,112 the ratemaking proposal for the Oakley PSA and project is consistent with our previous decisions regarding utility-owned generating projects,113 and the net capacity cost charge is fully consistent with Public Utilities Code
Section 365.1.
Finally, Joint Parties assert that approval of the Partial Settlement Agreement is in the public interest. In this regard the Joint Parties note that the Partial Settlement Agreement resolves the ratemaking and cost recovery issues raised in this proceeding, does not attempt to pre-determine whether all or a portion of the projects selected in the 2008 LTRFO should be approved by this Commission, and reduces customer costs by lowering the Oakley Project initial capital costs, fixing the O&M and capital addition costs subject to certain limited exceptions, and allocating the costs and resource adequacy benefits of the Mirant Marsh Landing and Oakley Projects among all benefitting customers.
CARE and PE oppose the partial settlement agreement. We disagree with these parties' arguments as set forth below. Both CARE and PE contend that the Commission should not conclude that the costs of the proposed projects are just and reasonable before it is "determined whether PG&E should procure the lower end of its need of 800MW or the higher end which is 1200MW."114 However, as the Joint Parties note:
The Partial Settlement Agreement addresses the ratemaking issues and cost recovery ... , but does not address selection of projects to meet the LRFO need amount. Under the terms of the Partial Settlement Agreement the Joint Parties reserve all rights to advocate for Commission approval of all or a portion of the projects in the 2008 LTRFO Application."115
Thus, the Partial Settlement Agreement only addresses the applicable ratemaking and cost recovery for those agreements that are approved by this Commission.
CARE goes on to argue that the Oakley PSA was not fairly evaluated against the PPAs. Joint Parties rebut this claim by general reference to the methodology for comparing these offers set forth in Chapter 4 of PG&E's opening testimony, by citing specific analytical processes used to make the evaluation of PSAs and PPAs fair, and finally by noting that the IE conducted a separate market valuation which produced similar results when comparing the PSA offers against the PPA offers.116
CARE also asserts that the Partial Settlement Agreement is unreasonable because it potentially allows PG&E to recover costs in excess of the initial capital cost estimate of the offer price (subject to a sharing agreement between ratepayers and shareholders), without the need for a reasonableness review. As noted by the Joint Parties, PG&E will recover in rates only the actual costs of its project, unlike a merchant generator that recovers a market return in its contract price.117 Thus, if the price of the project is less than anticipated the additional profit that would go to the merchant generator would go to ratepayers on a utility-owned cost of service project. Conversely, if the cost of the project is more than anticipated, where the merchant may opt to not perform, PG&E will continue to perform and pass on only a portion of the increased cost to ratepayers. CARE's complaint does not appear to give sufficient weight to the fact that the cost sharing mechanism in the agreement provides PG&E an incentive to control cost.
Finally,118 CARE argues that the report on operations of PG&E's facilities, which the Partial Settlement Agreement requires PG&E to provide to DRA and TURN, should be publicly disseminated.119 Join Parties respond that certain information in the proposed report is confidential and commercially sensitive. However, PG&E states that it has no objection to providing this information to non-market participants that are willing to sign a non-disclosure agreement.
For its part, PE argues that even if the additional MW are needed, the Proposed Partial Settlement Agreement should not be approved because PG&E has failed to explain how these facilities, which are different types of facilities with different operating profiles that do not meet the assumed operating profile in the Proposed Partial Settlement Agreement, can meet its needs.120 In particular, PE notes that "the Oakley Generating Station's planned operation limitations were recently significantly modified from one profile to three potential operating profiles and resubmitted to the CEC."121 The Joint Parties respond to this argument by noting that the dispatch scenarios referenced by PE are discussed in Attachment A to PG&E's reply testimony and that the terms of the PSA obligate these facilities to obtain a permit that allows it to meet or exceed the requirements.122 As the Joint Parties point out, if a permit that allows such operations is not obtained PG&E can terminate the PSA without costs to its customers.123 Finally, PE argues that the Proposed Partial Settlement Agreement should not be approved because the value of the new facilities to the ratepayers is unclear.124 The Joint Parties assert that this argument is without basis and note that "[t]he anticipated operating profiles of the [Oakley] Project are set forth in the PSA and have not changed."125
3.7.4. Conclusions Related to the Partial Settlement Agreement
We believe the Partial Settlement Agreement provides a way to resolve costs without obligating either the signing parties or the Commission to endorse any particular project. We agree that the Partial Settlement Agreement is just, reasonable, and in the public interest. We therefore, approve the Partial Settlement Agreement (as shown in Appendix A).
15 See PG&E Opening Brief (OB) at 17. After the 800 - 1,200 MW is augmented by the 312 MW of failed projects from the 2004 LTRFO the total need becomes 1,112 MW to 1,512 MW. Subtracting the 184 MW from the Mariposa Project from this number produces a maximum remaining need of 1,328MW.
16 In A.09-10-022, PG&E requests Commission approval of five contracts with GWF Energy LLC (GWF). In A.09-10-034, PG&E requests Commission approval of five contracts with Calpine Corporation (Calpine).
17 CARE OB at 4.
18 DRA OB at 5.
19 TURN OB at 6.
20 PE OB at 5.
21 Id.
22 PE OB at 6, citing Appendix A.
23 PG&E Reply Brief (RB) at 10.
24 PG&E RB at 8.
25 DRA OB at 7.
26 PG&E RB at 8-9.
27 PG&E RB at 8-9.
28 A.09-10-022 and A.09-10-034, Exh. 4, at 5-6.
29 TURN OB at 8, citing D.07-12-052 at 94 (rejecting contingency for renewables contract uncertainty) and 97 (rejecting over-procurement to address potential contingencies in the development of non-renewable generation).
30 Moreover, contrary to its claim that it can procure resources beyond those allotted, elsewhere in this proceeding PG&E has staunchly asserted that it is inappropriate for parties to challenge the MW range established for it in D.07-12-052. As stated by PG&E, "Commission policy disfavors reopening prior need determinations in a subsequent application proceeding to approve the agreements that are within its previously authorized procurement authority." PG&E November 16, 2010 Reply to Protest at 4.
31 CARE and CBE assert that PG&E failed to comply with law and Commission policy by failing to adequately consider environmental issues and failing to meet the requirements of the CEQA. Thus CUE/CURE assertion that "no party argues that the conduct of the 2008 LTRFO was improperly conducted or inconsistent with Commission directives" is erroneous. (CUE/CURE OB at 15.)
32 See Exh. PG&E-1 at 5-1 - 5- 4.
33 See Exh. PG&E-1 Appendix 5.1.
34 See Exh. PG&E-1 at 3-2.
35 See Exh. PG&E-2 at Confidential Appendix 1.3.
36 The G-score was calculated by standardizing the score for each criterion by subtracting the mean and dividing by the spread. The individual standardized scores were then averaged with adaptive weights.
37 Based on specified formulas and evaluation criteria, additional weight was given to criteria that had larger scoring variations (spread) than criteria with scores that clustered around the same value. As a result, if there was little variation within a category the weighting percentage for that category would be set to the low end of the predetermined range relative to other categories. See Exh. PG&E-1 Appendix 5.1, B-9.
38 See Exh. PG&E-1 at 3-9.
39 In a Confidential Exhibit (PG&E-2, Appendix 1.2) PG&E identifies the offers that it moved to the "shortlist."
40 PG&E did offer phone calls with participants that submitted offers that were not shortlisted (Exh. PG&E-1, at 3-9).
41 D.07-12-052 at 153.
42 D.07-12-052 Orders Paragraphs 3, 4, 10, 12, 15, 16, 18, 35, and 38 at 292-300, and Appendix A.
43 See e.g., D.07-12-052 Ordering Paragraph 15 at 292.
44 See Exh. PG&E-1 at 3-9.
45 In a Confidential Exhibit (PG&E-2, Appendix 1.2), PG&E identifies the offers that it moved to the "shortlist."
46 See Exh. PG&E-1, Appendix 5.1 at 6.
47 CBE OB at 3.
48 Id.
49 PG&E RB at 37.
50 D.09-10-017 at 1.
51 D.09-10-017 at 12.
52 IEP OB at 6; PG&E OB at 17; CUE/CURE OB at 6.
53 CUE/CURE OB at 5 and PG&E OB at 20.
54 Id.
55 CARE OB at 16, citing Exh. 501 at 2-3; PE OB at 8, citing Exh. 502 at 3 and 4.
56 CARE RB at 5.
57 Id. at 7.
58 Revisiting Path 26 Power Flow Assumptions at 3. See also 1 and 7. ( http://www.energy.ca.gov/2008publications/CEC-200-2008-006/CEC-200-2008-006.PDF).
59 2009 Forecast at 55, Table 10, Column 4, Row 21 (25,163 MW) minus Column 2, Row 21 (25,760 MW). The 2009 Forecast is incorporated into the CEC's 2009 Integrated Energy Policy Report at 52-54. The CEC adopted the 2009 IEPR on December 16, 2009.
60 In the PMR proceeding we are examining, among other things, the assumptions and methodology used to set the PRM, whether to recalibrate the PRM periodically, whether to establish a single PRM that applies throughout the service territories of utilities under our jurisdiction, whether to establish separate short-term and long-term PRMs, and how best to coordinate our PRM determinations with the needs of the California Independent System Operator (CAISO).
61 CUE/CURE OB at 10.
62 CUE/CURE OB at 10, citing Exh. 300 at 10:10-11.
63 On April 15, 2010, parties submitted a proposal to modify the Russell City PPA primarily to extend the deadline for the project's permit acquisition and construction. See CARE RB at 9.
64 D.07-12-052 at 29-30, fn. 38.
65 See CEC 2009 IEPR at 51.
66 See TURN OB at 11; CARE OB at 6 (asserting that PG&E calculations show a 330 MW reduction in demand); PG&E RB at 13; and Exh. 5 at 7.
67 PG&E OB at 5; CUE/CURE OB at 2.
68 See D.07-12-052 at 12; Exh. 501 at 5, citing D.07-12-052 at Table PGE-1; Exh. 200, Attachment 1.
69 PG&E RB at 14.
70 Exh. 5 at 12-13.
71 PE OB at 11, citing Exh. 500 at 3, Exh. 403 at 25.
72 See CARE OB at 10, fn. 35.
73 PG&E RB at 17.
74 PE OB at 15-16.
75 Exh. 5 at 13-14.
76 PG&E OB at 15.
77 PG&E OB at 22; PG&E RB at 17; CUE/CURE RB at 5, citing Exh. 15 - PG&E.
78 TURN OB at 11, citing Exh. 501 at 5-6.
79 PE OB at 12, citing Exh. 501 at 6.
80 Exh. 1 (PG&E Testimony) at 1-1.
81 PE OB at 13, emphasis added.
82 PG&E RB at 20, citing PE OB at 13-15.
83 Compare PG&E at 21-22 to PE OB at 14.
84 PG&E OB at 8, citing Exh. 5 at 15-23.
85 PG&E OB at 8, citing Exh. 1 at 3-13; Exh. 1 Appendix B at 22-23; Exh. 5 at 32; and
Exh. 300 at 2.
86 PG&E OB at 8, citing Exh. 5 at 17-19.
87 CARE RB at 13.
88 PE and CBE make generalized arguments (going to lack or need and failure to comply with CEQA, respectively) that are applicable to all of the proposed projects.
89 PG&E OB at 9.
90 PG&E asserts that units 6 & 7 were constructed 45 years ago and it is otherwise uncertain when they would shut down.
91 PG&E OB at 9, citing Exh. 1 at 6; Exh. 5 at 26-27.
92 PG&E OB at 9, citing Exh. 1 at 4-9; Exh. 300 at 13.
93 PG&E OB at 11 citing Exh. 1, Chapters 7, 8 and Appendix 5.1.
94 PG&E OB at 11, citing Exh. 5 at 21.
95 TURN OB at 14, citing Exh. 200 at 16-22.
96 CARE RB at 14, citing D.07-12-052 at 277.
97 CARE RB at 15.
98 CARE RB at 15.
99 PG&E OB at 11, citing Exh. at 3-25.
100 PG&E OB at 11, citing Exh. at 3-28.
101 Exh. 2, Appendix 1.1.
102 The total net capacity difference refers to the difference between the Oakley Project and the failed project or projects.
103 D.07-12-052 at 291, Conclusion of Law 6.
104 Exh. 1 at 4-5 and 4-6.
105 Id. at 4-8.
106 Exh. 1 at 3-19.
107 PG&E OB at 24, citing D.02-10-062 at 61, and D.06-11-048 at 33.
108 See Motion for Approval of Partial Settlement Agreement at 4-6 and Appendix A Sections IIIB(3), (4), & (5).
109 Motion for Approval of Partial Settlement Agreement at 7, and Appendix A, Section IIID.
110 Rule 12.1(d).
111 Motion for Approval of Partial Settlement Agreement at 8.
112 Motion for Approval of Partial Settlement Agreement at 9, citing Public Utilities Code Section 454.5(c)(1), D.09-10-017, and D.06-11-048.
113 Motion for Approval of Partial Settlement Agreement at 9, citing D.06-11-048 and D.06-06-035.
114 CARE Comments at 3; PE Comments at 2.
115 Reply Comments at 3.
116 Id. at 6, citing PG&E Opening Testimony at 4-11.
117 Reply Comments at 10.
118 CARE also asserts that PG&E should not be able to recover any costs related to the proposal as abandoned project costs. However, PG&E has not requested authority to recover abandoned project costs for the Contra Costa Project under the application or the Partial Settlement Agreement.
119 CARE Comments at 6.
120 Id. at 4-5.
121 PE Comments at 5, citing PG&E Reply Testimony at 23-24.
122 Reply Comments at 12.
123 Reply Comments at 13.
124 PE Comments at 5.
125 Reply Comments at 14.
