5. The PV Program Costs
Although we support the establishment of a solar PV Program to support the deployment of small and mid-sized PV systems as a valuable complement to the existing RPS program, we appreciate the concern raised with regard to program costs, specifically the concerns that the cost estimates provided are not reasonable and that the proposed UOG price does not effectively allow for the benefits of competition. In particular, we agree with the thrust of DRA's view that as proposed "neither the UOG nor the PPA component of the program will create the competitive environment that is supposed to protect the ratepayers from overpaying for renewable energy."25 Below, we discuss why our adopted PV Program changes the pricing structure PG&E proposed from a feed-in tariff approach for the PPA portion of the program, to an approach where the price is determined via a competitive solicitation. With regard to the price of the UOG portion of the PV Program, we believe PG&E's proposal with some modifications, under which it will conduct competitive solicitations for turn-key projects or EPC contracts and pass only the actual costs incurred on to ratepayers, coupled with a cost savings incentive mechanism, as described in more detail below, is adequate to protect ratepayers from excessive costs.
5.1. PV UOG Capital Costs
PG&E estimates the capital costs for the 250 MW of the UOG portion to be $1.45 billion. This corresponds to the average capital cost target of $4,275/kW direct current (DC) in constant 2009 dollars, including contingency, for the entire UOG portion of the PV Program.26
In previous sections, we have discussed parties' concern regarding the cost of the PV Program. The main concerns about the cost of the PV UOG are:
1. The estimates are unreasonable and unjustified.
2. The UOG price does not allow benefits from the competition.
3. The PV Program is more costly when compared to the CSI, the RPS, Southern California Edison's solar photovoltaic program (the SPVP) or other UOG projects.
In comments on the Alternate Proposed Decision (APD), both PG&E and SCE argue that the performance based ratemaking approach in APD as issued is unworkable for a variety of reasons. PG&E contends that basing its annual revenue requirement on a weighted average price per unit energy that is calculated from winning PPA bids ignores the fact that whether or not winning bids ultimately come online is far from certain.27 As such, using bid prices is likely to result in pricing that is unduly aggressive and unrepresentative of the actual cost of energy from the projects developed under the PV Program. PG&E additionally argues that a wholesale shift to the performance based approach undermines the long-term value of UOG projects to ratepayers.28 Under a PPA, at the end of a given contract's life an IPP can sell its energy at the then available market price. In contrast, ratepayers would only bear the variable cost for energy produced by a fully depreciated utility-owned asset. PG&E also argues that UOG projects serve important policy objectives that will not be realized if PG&E is unable to pursue any of the projects it proposed to deploy through the PV Program. PG&E suggests that UOG projects, pursued under cost of service ratemaking, provide a degree of certainty and speed to market that IPPs do not.29 Lastly, PG&E along with SCE argue that the dramatic shift in approach from what was approved in SCE's case is unjustified given the broad similarity of the proposed programs.30 Solar Alliance/Vote Solar offer additional arguments in favor of more traditional cost of service treatment for UOG projects, specifically arguing that the prices emerging from an IPP solicitation may not be indicative of what is required for PG&E to be willing to pursue these projects thus running the risk that as much as half of the PV Program's overall 500 MW capacity goal may not be pursued at all. They also suggest that the approach proposed in PG&E's application, whereby only actual costs of the UOG projects are passed on to ratepayers, and the stipulation that any costs in excess of the revenue requirement would be subject to a reasonableness review, should be sufficient to protect ratepayer interests.31 We believe some of these arguments have merit and are particularly concerned that the approach proposed in the APD as issued will not allow PG&E to pursue any UOG projects. Rather than compromise the ability of PG&E to effectively participate in the program it proposed, we will instead revert to the cost of service model as originally proposed by PG&E for the UOG portion of the PV Program, subject to some specific requirements and modifications to ensure that the costs ratepayers bear for these projects are reflective of market prices and PG&E faces meaningful incentives to keep it costs in check.
As noted above, PG&E has provided an annual capacity price target that, when combined with a contingency amount provides the basis for an overall revenue requirement for the total capacity costs incurred over the course of the program. Under this approach, should PG&E's total capital costs over the 5 year program prove lower than this amount, then the costs would be deemed reasonable and PG&E would be allowed to collect those costs from ratepayers without any further reasonableness review. If PG&E's capital costs exceed this benchmark, then it would be subject to a reasonableness review for the costs in excess of the revenue requirement. As a basic approach, we believe PG&E's proposal can serve to reasonably protect ratepayers from excessive costs, provided these costs result from a sufficiently competitive process and PG&E only passes its actual costs on to ratepayers. To the extent PG&E's earnings on projects undertaken pursuant to the PV Program are a function of its capital expenditures, parties are reasonably concerned with the accuracy of PG&E's annual capacity price targets as, under cost of service ratemaking, PG&E would appear to be motivated to pursue projects at or near the cost target. A relatively accurate cost estimate is therefore an important element in ensuring that the costs ratepayers ultimately bear under cost of service are limited to those that are truly reasonable.
PG&E has provided a variety of metrics to assess the reasonableness of its projected costs, including a bottoms-up cost estimate based on the deployment of 5 MW, ground-mounted systems on disturbed agricultural land to fulfill the overall capacity targets of the PV Program, as well as a number of comparisons to other solar projects and initiatives. None of these are perfect, for the reasons described below, however collectively they indicate that PG&E's proposed price benchmark is reasonable, given what data is available today.
With regard to PG&E's indicative cost estimates, there are some notable deficiencies identified by parties. CFC has demonstrated that PG&E's estimates of program costs lack important details including more specific information regarding where PG&E's plants will be built, how much land will be needed, or how much the land will cost. Greenlining also points to some deficiencies in PG&E's cost estimates. Specifically, Greenlining indicates that PG&E's cost forecast ignores the cost associated with panel disposal at the end of the panels' useful life. According to Greenlining, the panel disposal costs for the UOG portion alone could amount to about $27.5 million.32
We are not convinced by PG&E's response regarding the lack of cost estimates, particularly the response that the panel disposal cost was left out because of the uncertainty about how the panels would be disposed of, or the possibility that some panel manufacturers' voluntary take-back programs could reduce the costs of panel disposal. Moreover, PG&E's response that the unknown factors are implementation details is not compelling.
However, because these elements would, if included, presumably increase the capital costs above what PG&E has provided, and excess costs are subject to reasonableness review, we believe ratepayers have recourse should PG&E seek recovery of these costs. Similarly, to the extent these costs impact the O&M estimates, ratepayers again shall have the opportunity to challenge recovery through the Commission's reasonableness review in the context of PG&E's General Rate Case (GRC).
In addition to a bottoms-up estimate of system costs, another approach to determine if capital costs are reasonable is to look to similar projects that have been developed or are being pursued. To the extent analogous projects can be found, their costs can provide a range of costs within which PG&E's proposed projects can be expected to fall. As DRA notes the most useful comparison would be to projects of a similar size.33 Ideally they would also be ground mounted, in the same manner as PG&E proposes for the vast majority of projects it intends to undertake. For example RPS projects of a similar size and technology could provide a useful comparison. However, to date relatively few projects have actually come online in the RPS that are comparable to the projects PG&E has proposed, and to the extent they have been, relying on bid prices is potentially problematic given that a bid price is not necessarily reflective of the actual prices that ultimately emerge. Indeed, numerous projects in the RPS have come in for price "reopeners."
The CSI also fails to provide a reasonable comparison because projects under that program represent smaller projects deployed almost exclusively on rooftops. PG&E's PV Program envisions primarily ground mounted systems generally of a much larger scale than those seen in the CSI. Additionally, while from a ratepayer standpoint the cost of the CSI may be lower in that ratepayers provide only a partial subsidy to defray the costs of solar installation, from a societal standpoint, the installations PG&E has proposed are undoubtedly cheaper. As PG&E has indicated in testimony, the cost of CSI projects is almost double that of what PG&E has proposed.
SCE's SPVP while suffering from some of the same problems as the CSI in terms of comparability is perhaps a more useful metric insofar as it was approved to achieve some of the same ends as the program under consideration here. In SCE's case we approved a cost estimate of $3,500 (2008 dollars) per kW, excluding a 10% contingency and lease costs. This compares to PG&E's proposed cost of $3,493 per kW (2008 dollars), if one excludes land costs and contingency. Although PG&E has amortized the cost of the PV Program over 25 years and the SPVP's costs are amortized over 20 years, we believe the fact that PG&E projected costs are relatively close to those of SCE's suggests that, should the price benchmark be reached, PG&E ratepayers will be paying a comparable amount for largely similar benefits as SCE's ratepayers.
PG&E has also presented comparisons to other UOG projects in other states including a comparison to Public Service Electric and Gas Company's (PSE&G) "Solar 4 All Program" and Duke Energy Carolina's approved PV ownership program.34 PG&E notes that based on public data, the costs of the solar capacity developed under these programs is estimated at $6,442/kW for PSE&G and $5,000/kW for PSE&G and Duke, respectively. PG&E observes that these are substantially higher than the costs it anticipates under its program. The usefulness of these comparisons however, is somewhat limited owing to the lack of detail on the specific nature of these programs and how these programs may differ from that being proposed by PG&E here.
Perhaps the most useful data point we currently have is PG&E's pilot project. This project was developed and completed in 2009. The pilot project is intended to provide PG&E some initial experience developing a project that shares certain fundamental characteristics to those it proposes pursuing through the UOG portion of the program. As such we believe it is perhaps the most analogous of the projects available to us for comparative purposes. That said, it too, is an imperfect comparison as the pilot is relatively small in scale at only
2 MW. Thus, given the much broader range of project sized PG&E intends to pursue and assuming some economies of scale, it is likely that as a cost estimate using the pilot project will be unrealistically high. Also, the fact that the pilot was constructed on utility-owned land means that no incremental land costs were involved, something that is not assumed to be the case for the projects PG&E intends to pursue more generally. Regardless of these factors, we believe the costs of the pilot project provide a reasonable upper bound. We note that PG&E's proposed average capacity price target falls below its actual capital costs for the pilot project.
While each of the approaches presented to asses the accuracy of PG&E's proposed price benchmark are imperfect, we believe that taken together they generally show that PG&E's benchmark is within the realm of reasonableness and that it can, along with an appropriate contingency amount, serve as a useful basis for determining whether PG&E can collect monies from ratepayers for its investment in these facilities, or if its request should be subject to additional reasonableness review.
While we do not limit the construction of UOG facilities to PG&E owned land and substations, as this would unduly constrain the program, we strongly encourage PG&E to first develop on land that it already owns and that is also close to its substations for UOG projects before it acquires additional land. Doing so provides another means to ensure reasonable costs, and to mitigate other concerns raised by parties (e.g., environmental and eminent domain).
While we adopt PG&E's capacity price target today, we note that this estimate will become increasingly less accurate as time passes. The record in this proceeding strongly suggests that the market for solar PV is a dynamic one, with prices changing rapidly. For example, since the release of the RETI report cited by the Farm Bureau in its testimony the market conditions for solar PV have changed. A more recent RETI report indicates that solar PV costs may be lower than suggested in the earlier report. In fact, the Final RETI Phase 1B report distinguishes PV among all other technologies as one with significant potential for cost reductions in the future:
"Unlike most other renewable technologies, capital costs in the photovoltaic industry have significant potential to decrease, and there is considerable commercial interest in utility-scale "thin film" systems."35
Further, during hearings, PG&E's witness Wan noted that prices for PV have been declining.36 This statement is also consistent with some of the recent trade publications showing a trend in declining PV prices over time.37
Because PG&E has proposed conducting competitive solicitations and will only be passing the actual capital costs resulting from these solicitations through to ratepayers, ratepayers should reap the benefits of these anticipated price declines provided the solicitations PG&E conducts are sufficiently robust. To that end we believe it is appropriate for PG&E to enlist the services of an independent evaluator (IE) to oversee the solicitation process and provide an assessment of the fairness and robustness of each of its solicitations for UOG projects and the degree to which these solicitations conformed to the solicitation protocols. PG&E shall provide the IE reports regarding the UOG project solicitations it has conducted in its annual program compliance report to the Commission. The annual compliance reporting requirements are described in more detail in Appendix A.
In addition, we will also establish a cost savings incentive mechanism to better align PG&E's financial interests with those of ratepayers. As already noted, under cost of service ratemaking utilities face an incentive to increase their capital costs, which may be at odds with ratepayer interests to keep capital costs in check. Under the incentive mechanism adopted herein, should PG&E's actual average capital costs over the life of the program fall below $3920/kW(DC) the difference between the actual average capital cost per kW deployed and this $3920/kW threshold will be split between ratepayers and shareholders, with 90% of the difference going to ratepayers and 10% going to shareholders.38 This approach is conceptually consistent with the positions of CARE and DRA. In its testimony, CARE notes that,"...it is important for PG&E to have a financial incentive to minimize costs as well as a financial incentive to add electric generation fueled by renewable resources."39 In its Opening Brief, DRA suggests that cost overruns up to 20% in excess of the cost estimate should be automatically split between ratepayers and shareholders on an 80%/20% basis, with overruns beyond 20% subject to a reasonableness review.40 Although the mechanism established herein operates on cost savings as opposed to cost overruns, it embraces the notion that financial incentives tied to realized costs can play a part in motivating utility behavior. In particular, by giving PG&E shareholders an opportunity to share in some of the realized cost savings below the cap, this mechanism will encourage PG&E to keep costs down, and in so doing, save ratepayers dollars. We believe this approach, which rewards cost savings rather than automatically punishing PG&E shareholders for cost overruns, as DRA suggests, is preferable to the extent it will help drive costs below the cap rather than only influencing behavior above the cap. Furthermore, because all capital cost in excess of the cap are subject to a reasonableness review, we believe PG&E is already motivated to keep costs from exceeding the cap. This incentive mechanism encourages PG&E to realize costs below the cap. We choose $3920/kW as a reasonable cost threshold below which PG&E shareholders would begin to accrue incentives as this represents PG&E's capital cost estimate with no contingency amount. Although we believe the capital cost estimate plus the 10% contingency is acceptable for purposes of determining if the capital costs of PG&E's UOG projects are reasonable, we do not believe that PG&E should be expressly rewarded for not having exhausted the approved contingency amounts. This should further motivate PG&E to take the steps necessary to ensure robust solicitations for EPC and turn-key projects under the UOG portion of its program.
We note that that a number of parties have commented that the reasonableness of the costs should not be assessed in terms of dollars per unit capacity, but should instead be assessed in terms of dollars per unit output, as ultimately, it is the energy production from these facilities that is of value to ratepayers and to the state's renewable energy goals. Although we adopt a capacity price target in this decision and an associated revenue requirement for the recovery of capital costs, we expect PG&E's evaluation of project proposals to explicitly consider cost per unit output (i.e., levelized cost of energy) when comparing competing bids in its UOG solicitations. This information and how it is factored into the determination of which projects are ultimately selected from a given solicitation shall be provided to the IE and included in the IE's report to the Commission.
In addition to adopting a capacity price target we also need to address PG&E's requested contingency amounts. In its testimony PG&E proposes specific contingency amounts for various capital cost components.41 However, in our view the basis for these estimates appear insufficiently supported. For example, other than vague statements about varying levels of uncertainty and variability in the cost estimates PG&E, offers little in the way of empirical support for the proposed contingencies. A number of parties observed that the contingency amounts proposed by PG&E are higher than what we have approved in other instances. Rather than adopt PG&E's proposed contingencies, we believe a more reasonable approach is to adopt contingency values that correspond more closely to what we have adopted in other cases. We therefore, adopt an overall contingency amount of 10% consistent with what we adopted for SCE's SPVP.
Consistent with its request regarding recovery of capital costs for the UOG portion of its program, PG&E shall file for recovery of its capital costs in its GRC. The authorized revenue requirement shall be booked in its Utility Generation Balancing Account (UGBA) and a memorandum account shall be used to track the difference between its actual capital costs and the revenue requirement entered into its UGBA.
5.2. PV UOG Operations and Maintenance Costs
In addition to providing capital cost estimates, PG&E also provides estimates for the Operations and Maintenance (O&M) costs it anticipates incurring annually for the projects it deploys pursuant to the UOG portion of its proposed program. PG&E's O&M cost estimate consists of labor, materials, and contracts for operation and maintenance of the PV facilities and includes a 20% contingency factor due to uncertainties in the ongoing operation of the PV facilities.42 As with the capital cost estimates, these estimates were developed assuming the unit of deployment under the program will be a 5 MW, fixed panel, ground-mounted facility. PG&E indicates that its estimates are based on information obtained from solar equipment suppliers, consultants, and PG&E's best professional judgment.
PG&E's specific O&M cost estimates were contested by parties. The CFC in particular argues that the Commission cannot determine if the cost estimates are reasonable as many of the variables underlying these estimates are subject to change depending on the technology used and method of deployment.43 While we agree with CFC that there are a number of uncertainties in the underlying assumptions that necessarily translate into some uncertainty regarding PG&E's cost estimates, we find the simplifying assumptions PG&E made in conducting its assessment reasonable. In developing these estimates, assumptions do have to be made as it would be impossible to know, from the outset, exactly what technologies will be used, or where and how those technologies will be deployed without unduly limiting the flexibility of the program.
We note that under ideal circumstances, in addition to the indicative costs PG&E provided for its proposed projects, we would also have access to information regarding the actual O&M costs experienced by comparable facilities that are currently operating. PG&E did not provide any such comparable data on real-world projects, nor did parties, either in support of, or in opposition to PG&E's cost estimates. However, at the same time we recognize the difficulty of obtaining this information, and as such, believe PG&E's request is reasonably supported.
We are not persuaded, however, that PG&E's proposed O&M contingency amount of 20% is reasonable. While certainly there are reasons why O&M costs may vary from the estimates provides, PG&E's arguments in this regard seem to focus exclusively on the circumstances that may lead to higher than anticipated O&M costs. Yet many of these same uncertainties could be equally valid in support of an argument that actual costs may be below what PG&E has estimated. As such we adopt a contingency amount of 10% for PG&E's O&M costs. We believe adopting this lower amount will also encourage PG&E to be mindful of ongoing costs in selecting projects.
PG&E shall file for recovery of its O&M costs for UOG projects deployed pursuant to this program in its GRC, consistent with standard Commission practice, and subject to a reasonableness review. The performance of PG&E's facilities is an important consideration in our review of the O&M costs. Should PG&E's facilities on average produce less than 80% of their expected generation, as provided for in the compliance reports, it will argue strongly in favor of some disallowance or refund to ratepayers of at least some of these costs. To ensure that stakeholders have the ability to fully evaluate the reasonableness of these costs specifically, we require that in its GRC filing the O&M costs associated with this program be consolidated in one section. PG&E should provide sufficiently granular information for parties to understand the nature of the O&M expenses incurred by activity area (e.g., costs associated with panel cleaning, maintenance, vegetation management, security costs, etc.).
5.3. PV PPA Cost
In its application, PG&E proposes a fixed price for the PPAs, based on PG&E's expected LCOE for the UOG portion of the PV Program, which equates to a pre-TOD-adjusted contract price of $246/MWh. The Solar Alliance opposes the fixed price PPA for projects larger than 3 MWs. The Solar Alliance argues that PG&E's proposal for the fixed price PPA is inconsistent with the Commission's stated policy in D.07-12-052, which requires that all long-term procurement occur via competitive procurement mechanisms. The Solar Alliance also points out that the Commission in D.09-06-049 required a competitive process for the MWs to be developed by the IPPs for SCE's SPVP and that similar requirement should apply here. The Solar Alliance shares TURN's view that third party projects could sell energy at prices below the price of the UOG and also points out that PG&E itself has recognized that a competitive solicitation could secure prices lower than the fixed price offered by PG&E. Thus, the Solar Alliance advocates a competitive auction for projects above 3 MW.
While the Solar Alliance recommends against using a fixed price PPA for projects above 3 MW, it does believe a fixed price would work well for projects under 3 MW, and suggests we conduct a workshop to determine the price for such projects.
Greenlining is opposed to the fixed price for PPAs. It argues that the fixed price works as a disincentive to bidders to lower their price.
WPTF/DDAC also argues that the fixed price conflicts with several Commission decisions, including the Commission's competitive market first approach. It notes that Commission decisions that have encouraged competitive procurement have never mentioned fixed price PPAs. It further adds that such a price would also be inconsistent with the criteria for UOG and Commission policy that encourages merchant generation development.44 In addition, WPTF/DDAC adds that the fixed price will provide no price competition that could benefit the ratepayers.
CFC also notes that the fixed price may result in higher costs than the competitive procurement.
TURN also opposes the fixed price, stating that the fixed price could create potential windfalls for the developers. TURN argues that third party developers may be able to achieve lower prices than UOG due to many factors including the benefits of federal tax incentives, lower cost of capital, and changing market conditions, but under a fixed price structure, the financial benefits of these lower costs would be realized only by the developers. TURN advocates that to the extent that lower prices can be achieved, ratepayers should be able to benefit from these savings in the form of lower rates. Because a competitive procurement process would allow ratepayers to reap the benefits of the lower prices, TURN recommends we reject the fixed PPA price and adopt a competitive procurement process instead.
DRA also proposes that PG&E's program be modified to include cost-competitive PPA solicitations. Specifically, DRA recommends that instead of creating another renewable energy PPA solicitation process, the Commission adopt a PPA solicitation process similar to the market-based pricing mechanism, or Renewable Auction Mechanism, proposed by Energy Division Staff in Rulemaking (R.) 08-08-009.
In response to the above objections to the fixed price PPA, PG&E argues that if PPA price is not fixed, several aspects of the program including project selections, contract negotiations, execution, and approval process could become more difficult and contentious and result in delays for the program. Furthermore, PG&E asserts that there is a probability that without a fixed price, projects would focus on seeking opportunities to cut costs for the purpose of the bid rather than maximizing the viability of the projects, even though those measures could threaten the long-term viability of the projects.45 Thus, PG&E argues that the proposed fixed price PPA is what it will reasonably cost in a competitive market to build viable, small and mid-size PV facilities.
We will not adopt a fixed price PPA as proposed by PG&E, because it has several shortcomings and there is a risk that paying a fixed price for PPAs could result in higher prices for PPA contracts and lead to overpayment by ratepayers. Furthermore, given that the price proposed by PG&E is derived from an estimate of solar system costs that are likely to change, we do not feel it would reasonable to adopt this as a basis for the price offered to PPA projects. Instead, we adopt a competitive process for the PPA selection. As we have previously stated our preference for a competitive procurement process, this approach will ensure that this program achieves its objectives at the lowest cost to ratepayers.
Many parties raise concerns with using a fixed price PPA and suggest replacing it with a competitive process. The major criticism of the fixed price approach is that it does not result in the best prices for the ratepayers, as would a competitively-based price. This view is shared not only by those who support the PG&E's PV Program proposal, but also by others who oppose it.
DRA, while urging the Commission to deny the application, stresses that if the Commission were to approve the program, it should require competitive price bidding for the PPA portion to protect ratepayers.46 Greenlining expresses a similar concern regarding the application and states that "the Commission should not approve a pricing scheme that forgoes savings achievable in a fully competitive market."47 The Solar Alliance, while supporting the application, recommends a competitive procurement process. WPTF and DACC also suggest the Commission reject PG&E's fixed price approach in favor of truly competitive RFOs in order to attain the best possible price.
At the heart of the concern raised by various parties regarding the fixed price approach for the PPAs is the notion that the benefits that might be achieved through meaningful price competition will not accrue to ratepayers under this approach. Furthermore, our ability to administratively determine the "right price" that will both encourage projects to come online while also ensure that ratepayers pay no more than they would have otherwise for the same product, is fundamentally limited. As already explained earlier, the market for solar is changing rapidly. The fixed UOG price PG&E proposes is based on an estimate of PG&E's cost for building PV projects and the result of several assumptions specific to utility ownership. These assumptions also introduce significant uncertainty particularly in future years. In addition, as witness Jeung suggests "A number of factors impact projects economics, including location, equipment prices, labor costs, and transmission costs."48 Thus, there is no basis for adopting a fixed price for projects that not only could vary in size, but also would have different characteristics, including ownership. These project-specific attributes and associated costs are best sorted out via a competitive process where each project's specific circumstance is considered and reflected in its bid.
Second, accepting that the UOG price is a reasonable estimate for what it would cost the utility to develop these projects, PG&E has not provided a clear justification for why the same price would also be reasonable for PPAs. As TURN correctly points out, several factors including lower costs of capital could enable third party developers to offer PPAs at prices below the forecast of UOG. Under PG&E's fixed price PPA, however, the financial benefits of potentially lower third party costs cannot be realized by ratepayers. Finally, there is no reason why PG&E cannot use a competitive price and still select the most viable projects.49 The PV PPA evaluation process will be similar to the process used in the RPS RFO evaluation and will include a number of criteria, including project viability. The same evaluation process and steps as described in PG&E's testimony for the fixed price PPA could also be used for the PPAs with the competitive price. PG&E's concern that if the PPA price is not fixed it could impede the focus on selecting projects with the highest viability is not valid, because a viability assessment would remain as a factor in the selection of the projects even with competitive price added as a criterion. In other words, although it is true that adding a new criterion could change the selection process, it does not follow that it will necessarily result in selection of less viable projects. Additionally, we disagree with PG&E's contention that a competitive process engenders additional complexity and will result in delays. These matters can be addressed by adopting a non-modifiable standard contract as well as specific deadlines for when winning projects have to be online.
We also decline to adopt DRA's proposal to incorporate the PPA solicitation into the Renewable Auction Mechanism (RAM) that is being considered in R.08-08-009. We may reconsider whether to incorporate the PV Program solicitation with RAM at a future date, depending on the outcome of the RAM proposal.
With regard to projects sized 1-3 MW, we do not adopt Solar Alliance's proposal that projects in this size range receive an administratively determined price rather than going through a competitive solicitation. No compelling arguments have been presented that suggest that these projects offer substantially different benefits than those offered by the other projects that would be eligible under this program and so we see no reason to accord them special treatment. This program is a means to an end, namely the expeditious deployment of solar facilities to help fulfill the state's renewable energy mandates. In our view there is not sufficient evidence on the record to believe that the smaller projects the Solar Alliance is concerned with are necessarily more effective at achieving this aim, or so much more so as to justify potentially higher costs to ratepayers to support their deployment. Therefore, we believe they should compete alongside other eligible projects. To that end, we reject Solar Alliance's proposal.
Finally, we agree with TURN that PG&E should provide information to potential bidders in the solicitation indicating preferred locations to interconnect. This information could assist project developers to secure suitable locations to minimize the risk of facing unforeseen interconnection costs. In providing this information, PG&E should identify preferred locations on the grid where the deployment of DG could help address anticipated peak load growth or help congestion.
Finally, we shall also require PG&E to enlist the services of an independent evaluator to assess the overall fairness and robustness of the solicitations PG&E holds for PPA projects. This is consistent with the approach taken in the RPS program, as well as what we have adopted here in the context of PG&E's solicitations for turnkey and EPC contracts under the UOG portion of the PV Program. PG&E shall provide the IE reports regarding the PPA project solicitations it has conducted in its annual program compliance report to the Commission.
Consistent with PG&E's requested approach to cost recovery, the costs of energy procured from IPP projects shall be recovered through ERRA pursuant to standard Commission practice.
25 DRA Opening Brief at 5.
26 Table 6-9 in PG&E's prepared testimony provides additional information regarding the derivation of the $1.45 billion revenue requirement based on an average capital cost of $4,275/kw(DC).
27 PG&E Opening Comments on APD; at 2-5.
28 Ibid; at 6-7.
29 Ibid; at 7.
30 Ibid; at 7-8; also see Southern California Edison Company Opening Comments on APD; at 3-4.
31 Solar Alliance/Vote Solar Opening Comments on APD; at 9-10.
32 Greenlining's Opening Brief at 13.
33 Exhibit 101 at 7.
34 Exhibit 3.
35 Final RETI Phase 1B report ( http://www.energy.ca.gov/2008publications/RETI-1000-2008-003/RETI-1000-2008-003-F.PDF), at 5-27.
36 TR Volume 1 at 9.
37 http://www.solarbuzz.com/FastFactsIndustry.htm.
38 For example, assuming PG&E deploys 250 MW(DC) of capacity and the actual average capital cost over the life of the program is $3700/kW, under the cost savings incentive mechanism adopted herein PG&E would, for every kW of UOG deployed receive 10% of the difference between $3920 and $3700, or $220/kW. This would yield $22/kW * 1000 kW/MW * 250MW = $5,500,000.
39 CARE Opening Testimony, at 6.
40 DRA Opening Brief, at 11.
41 Exhibit 1, "Prepared Testimony of PG&E," at 4-6, lines 17-23.
42 Exhibit 1 at 5-6.
43 Consumer Federation of California; Opening Brief; at 13.
44 WPTF/DDAC Opening Brief at 4.
45 PG&E Reply Brief at 26.
46 Exhibit 101 at 24.
47 Greenlining Opening Brief at 9.
48 Exhibit 4 at 3-2.
49 In fact, the Commission recently implemented the competitive procurement portion of SCE's Solar PV Program, which includes rigorous eligibility and project viability screens. See Resolution E-4299.
