9. RAM Standard Contract

ED proposes that RAM standard contract terms and conditions not be negotiable. Similarly, bid prices should not be negotiable.88 We agree.

We streamline procurement with the RAM by adopting a standard, non-negotiable contract for each IOU, a program capacity cap, a market mechanism to determine contract price, and other standardized protocols. The result is to provide IOUs, project developers, and the Commission a simplified approach to accessing a market segment that can contribute substantially to meeting the state's RPS, GHG, and other goals. This makes it relatively easier and less costly for all stakeholders.

We decline to allow negotiations within the RAM since this will add time, cost, and complexity to the RAM program. Buyers and seller in this market segment have other opportunities that permit negotiations if and when necessary, in the form of the annual RPS solicitation. In this context, it is reasonable to make the RAM program "take-it-or-leave-it" (non-negotiable). To allow for contract negotiations is, in our view, in conflict with the goals of this program which is to provide a streamlined approach to renewable procurement for smaller scale RPS projects.

ED proposes that each IOU start with its Existing FIT contract and add or amend terms as needed to develop RAM, with the three IOUs having consistent terms and conditions for the new terms. ED recommends that a uniform standard contract for all three IOUs be required over time. Parties dispute the need and desirability of uniformity, with IOUs generally in opposition and some parties in support.

While we appreciate ED's desire for uniformity across each of the IOUs' RAM contracts - with one uniform contract the goal - we decline to require such rigid uniformity here. We will allow each IOU to develop its own standard contract, which will be non-negotiable and standard for all winning bidders in a specific RAM auction. We also decline to identify which contract each IOU should start with in developing a standard RAM contract. We do strongly encourage the IOUs to begin with an existing standard contract that is simple, currently in use, and that has been vetted through a stakeholder process. Each IOU shall include its proposed standard contract as part of its advice letter filing implementing RAM, as described in Section 12.1 below. While we do not mandate a uniform contract, there are some basic elements within those contracts that we require to be the essentially the same, as described in the section 9.3 below.

We now discuss specific contract terms and conditions raised by ED and addressed by parties. If not addressed in this decision, we allow the IOUs to propose contract terms and conditions, subject to Commission approval through an advice letter.

The Existing FIT provides that a project must be operational within 18 months or the contract is subject to termination. Termination is not automatic. The IOU must provide notice and opportunity for parties to address termination before termination becomes effective. If unable to reach agreement on a reasonable schedule, the IOU may move forward with termination. (See D.07-07-027 at 38-40.)

For RAM, ED proposes automatic contract termination after 18 months, with developer forfeiture of the proposed project development security deposit. A one-time six-month extension may be permitted, according to ED's proposal, if the project can successfully demonstrate the cause of the delay is due to regulatory processes outside of its control such as permitting or interconnection delays not caused by the developer. ED recommends that delay due to business risk, such as lack of financing or equipment delivery delay not be an acceptable justification for the granting of an extension. If terminated, ED says the project may participate in another RPS opportunity, such as the next RAM auction or annual competitive RPS solicitation.89

Parties offer a range of views on the proposed 18-month commercial operation date, and possible extensions. CEERT and some parties support ED's proposal in part or whole. CALSEIA says projects over 5 MW may need more time to obtain permits, and recommends considering a longer timeframe combined with project milestone requirements.90 PG&E suggests specific times frames, with extensions at the discretion of the IOUs, but proposes that termination only occur when there are true constraints, such as the program cap or transmission or distribution limits.91 FuelCell Energy does not object to ED's proposal as long as an appropriate force majeure clause covers events outside the parties' control.92 GPI opposes the 18-month provision, asserting it is unnecessary and harmful unless the program cap is a binding constraint that is actually limiting other projects' participation in RAM.93

IEP contends that ED's recommended strict 18-24 month requirement will limit eligibility to projects that (a) are already interconnected or have strong assurances that no upgrades will be required and (b) have already completed permitting. IEP says this will considerably shrink the universe of potential projects because developers will be required to make significant financial expenditures before they can sign a contract. Moreover, few lenders will agree to finance a project that will lose its contract if it encounters even ordinary construction delays. IEP suggests the cure for these concerns is to allow the project 18 months after contract signing to begin material on-site construction.

In the alternative, IEP suggests that technology-specific timelines may be established in recognition of the different degrees of construction and permitting complexity associated with different renewable technologies.

We think there is merit in a strict length of time provision for RAM, not unlike in the Exiting FIT. This streamlines RAM administration and attracts projects that are more viable because they are further along in the project development process. We find that the best approach is to set meaningful time limits, subject to one justifiable extension. Therefore, we adopt an 18-month timeframe, with the potential for one six-month extension. The 18-month deadline begins upon contract execution between the IOU and the seller. We expect the IOU to limit the reasons for an extension to regulatory delays outside of the developer's control. In order to grant an extension due to regulatory delays, the project, for example, must show that it filed applications timely, paid fees timely, and is responsibly pursuing the necessary applications. An IOU should terminate a contract at the end of 18 months if the project fails to adequately demonstrate the merits of an extension.

We expect ED and parties to monitor IOU extensions, and take them into consideration as part of future recommendations relative to IOU administration of the RPS and RAM programs.

We do not adopt IEP's proposal that we move the critical milestone deadline from commercial delivery to the commencement of material on-site construction. The record does not contain a definition of material on-site construction, and we decline to develop one. Disputes are likely even if the term is defined. Therefore, changing the deadline from commercial operation to material on-site construction does not resolve the issue.

Similarly, we decline to adopt technology-specific timelines that recognize the different degrees of construction and permitting complexity associated with different renewable technologies. The establishment of any timeline requires judgment, and legitimate delays can occur relative to any timeline. Technology-specific timelines do not resolve the issue.

The Existing FIT does not require a development deposit. ED proposes that the RAM require a development deposit of $20/kW. ED recommends that this deposit is either (a) refunded once the project is operating or (b) applied to the subsequent performance deposit.

In response to ED's proposal, parties recommend a range of development deposits from zero94 to at least $30/kW.95 Recurrent recommends increasing the deposit to at least $30/kW in order to strengthen project and developer viability requirements. Opponents assert that even a small deposit is an unnecessary barrier, but provide no evidence. On the other hand, SCE shows that a $20/kW deposit is less than 1% of an estimated minimal $2,100/kW installed cost for the least expensive renewable project.96

Several parties argue that the pay-for-performance feature of paying only for the delivered product provides sufficient incentive for a developer to bring its project to successful commercial operation, and no additional incentive is necessary. Sustainable Conservation argues there should be no development deposit since it is already a significant challenge to obtain project financing and a project should not have to raise additional capital just to hold a place in the queue.97

We recognize that a development deposit is appropriate because IOU costs relative to a failed project are not zero (e.g., there are costs to obtain replacement power). In addition, because the renewable goals are finite, it is important to take steps to ensure more viable and credible projects are selected as those projects that are selected necessarily crowd out other opportunities. To the extent putting capital at risk in the form of a security deposit will screen more speculative projects out of the solicitation, it is to ratepayers' benefit to require such deposits. This needs to be balanced against the risk that if set too high, we will exclude projects that might be reasonably viable but which lack the necessary capital to post a large security amount.

Additionally, because the security deposit is at risk, it will at some level be reflected in the price that developers bid into a given solicitation. The deposit provides collateral against those costs without requiring a complicated, potentially time consuming and costly study of actual damages. A deposit subject to forfeiture also provides a small additional incentive for the developer to complete the project within the allotted timeframe. Further, a reasonable deposit will help filter out projects that investors believe have no chance of success.

In SCE's RSC program we note that they have implemented a tiered development security deposit that varies based on the size of the project. We believe this approach has merit as it affords a way to balance the benefit of limiting projects to those that are likely to be the most viable with the risk of unnecessarily limiting the field of developers able to participate in the program. As an initial approach for the initial 1000 MW authorization, we believe it is appropriate to look to the precedent established in the context of existing Commission vetted programs targeting similar resources. In the context of SCE's Solar Photovoltaic Program, we adopted a security deposit of $20/kW. This program targets facilities primarily in the 1-2 MW size range. In the PG&E's Solar PV Program, we adopted a security deposit of $20/kW for projects less than 10 MW and $35/kW for projects 10 MW or greater. In contrast, for annual RPS solicitations, security deposits range from $30/kW to $50/kW for intermittent resources and $60/kW to $100/kW for baseload resources. In addition, in SCE's filing of its 2010 Annual RPS Procurement Plan, it has requested to increase its deposits from $30/kW to $60/kW for intermittent resources and from $60/kW to $90/kW for baseload resources. Furthermore SCE used these higher deposits in its RSC solicitation. Based on this information, we find it reasonable to require a $20/kW development security deposit for projects 5 MW and smaller, and a $60/$90 per kW deposit for intermittent and baseload resources, respectively, for projects greater than 5 MW and up to 20 MW in size. Should Energy Division find that these requirements undermine the goal of promoting a sufficiently competitive market, or that they are not serving their intended purpose, they may adjust these requirements via the resolution process.

The current FIT does not require a deposit to assure performance.98 However, ED proposes no performance assurance/delivery term security deposit (herein called performance deposit) for projects between 1.5 MW and 5 MW.99 ED proposes a performance deposit of 5% of expected total project revenue for projects greater than 5 MW.100 Parties present a range of views from no performance deposit for any project to all projects paying a performance deposit.

We adopt a performance deposit for all projects electing subscription under the RAM. We do this because, as PG&E and others convincingly argue, the deposit is a form of collateral that helps compensate the IOU and ratepayers for damages from performance failure, particularly if the project ceases operation and has few or no remaining assets. 101 We also note the desirability of a performance deposit as explained by SCE:

"SCE's experience, however, is that developers continuously reevaluate the financial performance of their project as their operating and maintenance costs, the energy prices available elsewhere in the market, and their tax incentives change over the life of the contract. Determinations are made whether continued performance under a contract is warranted versus other alternatives that may be available to maximize the developer's return on investment. Developers have in the past and continue today to seek ways to terminate their obligations under existing contracts because they believe a better deal may exist. Performance assurance [deposit] is designed to mitigate the consequences of SCE having to replace the failed project with a similar project."102

For projects less than 5 MW, we adopt a performance deposit equal to the development deposit ($20/kW, or less than 1% of the capital cost of the least expensive project).103 That is, the development deposit converts to a performance deposit.

For projects 5 MW and larger, we adopt a performance deposit of 5% of expected total project revenues. We adopt this deposit for projects 5 MW and larger based on ED's recommendation, also noting that SCE requires a similar performance deposit for projects 5 MW and larger as part of its RSC program. We think SCE has reached the right balance between the burden of a larger performance deposit and project size.104

We are not persuaded by Sustainable Conservation, IEP and others who assert without evidence that a performance deposit makes it unreasonably difficult to obtain financing. IEP claims, for example, that an obligation of 5% of expected total revenues for a 20-year contract means a performance deposit equal to one year of revenues, which IEP says "can be prohibitively expensive."105 Even if it "can be" for some, we have no evidence that it is prohibitively expensive for all. Projects of 5 MW and larger must obtain financing of several million dollars. There is no evidence that the incremental difficulty of obtaining financing to also cover the performance deposit is unreasonable or fatal.106 On the other hand, a relatively small performance deposit will help filter out projects that investors believe have no chance of success, provide incremental incentive (in addition to pay-for-performance pricing) for successful performance, and set aside a modest sum relative to possible damages.

A performance deposit becomes a cost of doing business. It does not give any project a particular advantage or disadvantage because it is uniform for all projects of the same size. A rational bidder will include this cost, along with all other costs, in its bid. A winning bid will, therefore, include this cost, which will in turn be paid by ratepayers. A performance deposit provides some ratepayer security (insurance) against poor performance or project failure, and is a reasonable price for ratepayers to pay over the life of the contract (via winning bid prices) for modest protection.

Solar Alliance and Vote Solar propose, without supporting evidence, that the performance deposit be limited to the lesser of six months or 5% of expected contract revenue.107 We believe ED's proposal strikes the appropriate balance, and Solar Alliance and Vote Solar do not convincingly demonstrate why it should be modified.

The Existing FIT requires (a) performance consistent with good utility (or prudent electrical) practices, (b) liability insurance against IOU losses, and (c) project liability for damages based on an IOU's direct, actual losses. ED proposes keeping these requirements and adding an explicit minimum performance threshold. Specifically, ED proposes a performance obligation of 140% of expected annual net energy production based on two years of rolling production, subject to payment of damages for failure to meet the performance obligation.108 In addition, ED proposes that IOUs bear the risk of scheduling deviations if the generator (a) participates in the CAISO Participating Intermittent Resource Program (PIRP), (b) provides the IOU, as scheduling coordinator, with timely information on availability or (c) provides the IOU with remote access to metered output. In conjunction with 10- to 20-year contracts, the performance obligation facilitates IOU long-term renewable resource planning, according to ED.109

Comments range from support to opposition. IOUs generally support ED's proposal. PG&E proposes additional conditions to prevent sellers from underestimating output. For example, PG&E recommends an IOU pay the project the lower of spot price or 75% of contract price for output in excess of 120% of forecast net production. This facilitates IOU scheduling and planning, according to PG&E, by not letting the seller under-forecast output to avoid the risk of paying damages. PG&E also recommends specificity regarding "timely information" of project schedules to improve an IOU's ability to remarket excess RAM electricity.110 SCE proposes use of predetermined capacity factors by technology.111 Sustainable Conservation and other parties oppose ED's proposal on the basis that it is too onerous and makes financing more difficult.

It is appropriate to require performance consistent with good utility (or prudent electrical) practices, liability insurance against IOU losses, and payment of damages based on an IOU's direct, actual losses. In addition we agree with Energy Division that it is prudent to adopt a minimum performance requirement. To that end, we adopt Energy Division's proposal of 140% of expected two-year production as a simple and straightforward approach. This obligation is identical to SCE's performance obligation in its RPS Pro Forma contract.

The Existing FIT limits damages to actual, direct damages, but does not state a maximum dollar amount. In no event under the Existing FIT is either party liable for consequential, incidental, punitive, exemplary or indirect damages, lost profits or other business interruption damages, regardless of cause.

ED proposes the RAM have a damage limit, wherein damages are capped at a level equal to the contract price minus average market price for the term year, but no greater than $0.05/kWh and no less than $0.02/kWh. In support, ED says a damage calculation is needed to enforce a performance obligation, but should be capped to ensure the contract may be financed and provide certainty to investors.112

Parties present a range of views. PG&E and SCE support ED's proposal. SDG&E says the $0.05 to $0.02 range is arbitrary and damages should be uncapped. Sustainable Conservation, Redwood Renewables, and others state that ED's proposed damages are excessive, even if limited, and should be reduced or eliminated. IEP asserts that a project should not be penalized for failure to perform by a minimum $0.02/kWh penalty (e.g., if the market price is lower than the contract price).

We adopt the provisions of the Existing FIT for the RAM standard contract and decline to adopt ED's proposed damage limit.

We have no data to specifically relate the risk and cost to ratepayers of capped damages compared to the benefits, if any, from an increased ability to finance a project or provide certainty to investors. We have no specific data to assess the merits of the recommended range (i.e., $0.05/kWh and $0.02/kWh) versus another range. We also agree with IEP that it is unreasonable to set a minimum penalty even when actual damages are less. In the absence of information justifying a change, we think the best approach is to limit damages to actual amounts as we do now.

PG&E's Existing FIT defines force majeure, and states that during a force majeure event PG&E (a) need not pay for energy or capacity and (b) may require the seller to curtail, interrupt or reduce deliveries. The Existing FIT contracts for SCE and SDG&E do not define force majeure and do not contain provisions similar to those of PG&E. All three Existing FITs contain various terms related to other events of default, such as failure by the seller to take corrective action after notice and seller's abandonment of facility and no party objects to them.

ED proposes that terms for force majeure and events of default be included in the RAM contract since these terms protect both buyer and seller from events outside their control.113 Parties generally support ED's proposal, and thus provide limited comments.

We agree with Solar Alliance and Vote Solar that force majeure must be defined, and, to the extent there is liability, provisions must protect both buyer and seller, not just the IOU.114 Terms for force majeure and events of default should be part of RAM. Consequently, IOUs should specify force majeure provisions and events of default in their RAM standard contracts.

Insurance provisions in the Existing FIT contracts vary. PG&E's FIT includes a general liability insurance requirement of no less than $1 million for facilities between 0.1 MW and 1.5 MW (with reduced limits for smaller facilities), along with necessary requirements and conditions (for example, insurance is primary and not excess to insurance maintained by PG&E). SCE's and SDG&E's Existing FITs require general liability insurance of not less than $2 million for facilities between 0.1 MW and 1.5 MW (with reduced amounts for smaller facilities), along with necessary requirements and conditions. ED proposes that existing terms continue.

Comments on insurance requirements vary. IOUs recommend higher insurance amounts for larger projects. SCE states it is revising insurance requirements under its Existing FIT, but provides no specifics. FuelCell Energy and others agree with ED that existing insurance requirements are reasonable.115 Solar Alliance and Vote Solar state that insurance requirements should be consistent across the three IOUs, and recommend adoption of the levels used by PG&E.116

Environmental Council asserts insurance requirements are overly burdensome, and that there is limited need for insurance because of existing CAISO requirements. It also says the threat of losing queue position and forfeiting deposits limits the need for insurance.117

We are not convinced by Environmental Council's claims that insurance requirements are overly burdensome. Environmental Council presents no credible data showing that the level of insurance premium for a $2 million policy is an overly burdensome percentage of either investment or operating cost. Nor does it show that the threat of losing queue position and deposits adequately changes behavior to offset or eliminate the risk of insured loss, or that the level of deposits adequately addresses potential losses covered by general liability insurance.

Insurance is a reasonable and time-tested method to address risk and potential loss and we expect the IOUs to require insurance in their RAM standard contracts. However, we allow the IOUs to determine the amounts and the terms and conditions of such insurance. Subject to Commission approval through a resolution, we expect them to take reasonable actions to protect their ratepayers while also promoting the competitive energy market. To this end, we encourage the IOUs to develop "tiered" insurance requirements, as appropriate, to address the circumstances of smaller projects or those using different technologies.

PG&E's Existing FIT requires that PG&E be the seller's scheduling coordinator.118 ED proposes that the IOU bear the risk of scheduling deviations if the generator provides the IOU, as scheduling coordinator, with timely information on its availability.119

We adopt a requirement for the RAM that the IOU be the scheduling coordinator for the project, and the IOU bear the risk of scheduling deviations if the generator provides the IOU, as the scheduling coordinator, with timely information on its availability. The IOU can decline scheduling coordinator responsibilities only upon a written, affirmative request from the seller that the IOU not be the scheduling coordinator, or if unable to perform scheduling coordinator duties (e.g., for a project out of its service area). This approach simplifies RAM administration and is reasonable.

88 August 2009 Proposal at 9.

89 Pricing Proposal at 8-9.

90 CALSEIA Terms and Conditions Comments at 4.

91 PG&E Terms and Conditions Comments at 8.

92 FuelCell Energy Terms and Conditions Comments at 3.

93 GPI Terms and Conditions Comments at 4.

94 See, for example, Sustainable Conservation Terms and Conditions Comments at 7; Redwood Renewables Terms and Conditions Comments at 5.

95 See, for example, Recurrent Pricing Comments at 7.

96 SCE Terms and Conditions Reply Comments at 5.

97 Sustainable Conservation Terms and Conditions Comments at 7.

98 A deposit is not required, but performance must be consistent with good utility (or prudent electrical) practices, the project must secure liability insurance, and poor project performance may result in the project owner paying damages to the IOU based on direct, actual losses. See, for example, PG&E § 399.20 PPA at Sections 4.6, 6.0 and 8.0. Also see SCE Renewable and Alternative Power Agreement and SDG&E Renewable Power Agreement at Sections 5.4, 8.0 and 9.0.

99 In this case, the project's development deposit is refunded, and is not applied to the performance deposit.

100 The $20/kW development deposit is applied to the performance deposit.

101 Those damages might include the cost of replacement power, for example.

102 T&C Reply Comments at 6-7.

103 The least expensive project is about $2,000/kW. (See Chapter above on Pricing Approach.)

104 It is informative to compare this to the performance deposit in the current RPS annual solicitation. Current PG&E annual solicitation protocols for any size project require a deposit of 5% of average expected project revenue (expressed as six months revenue for a 10-year contract, nine months revenue for a 15-year contract and one year revenue for a 20-year contract). (See PG&E Protocol June 29, 2009 at 23.) SCE requires a deposit for any size project of 5% of the notional value of the total energy payments expected during the term of the agreement, but not less than $1,000,000. (SCE Procurement Plan, July 17, 2009, Appendix E at 31.) SDG&E requires a delivery term security for any size project of $15/MWh times twice the annual estimated energy amount. (SDG&E Procurement Plan, June 22, 2009, Appendix A at 25.)

105 T&C Comments at 9.

106 Assume the investment cost for a five MW project is $3,000/kW, making the investment cost $15 million. If the project capacity factor is 33% and the FIT rate is $0.10/kWh, the total revenue over 20 years for a 20-year contract is $28.9 million. A performance deposit of 5% requires a deposit of $1.45 million. We are not persuaded that financing $16.45 million rather than $15 million is so difficult as to justify a different or no performance deposit. On the other hand, a deposit of $1.45 million reasonably provides additional incentive for good performance and collateral against potential damages caused by project non-performance or failure.

107 T&C Comments at 9.

108 That is, each year the project must deliver about 70% of its forecast annual net energy production.

109 March 2009 Proposal at 11.

110 PG&E Terms and Conditions Comments at 11-13.

111 SCE Terms and Conditions Reply Comments at 7-8.

112 March 2009 Proposal at 11-12.

113 March 2009 Proposal at 12.

114 Solar Alliance and Vote Solar Terms and Conditions Comments at 9.

115 FuelCell Energy Terms and Conditions Comments at 7.

116 Solar Alliance and Vote Solar Terms and Conditions Comments at 9.

117 Environmental Council Terms and Conditions Reply Comments at 9-10.

118 PG&E § 399.20 PPA at 10.1 "Scheduling Obligations."

119 March 2009 Proposal at 11.

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