8. Eligibility

The original legislation requiring the Existing FIT,63 and our initial implementation of that program in D.07-07-027, required that a generator serve on-site load and be an existing retail customer of the utility to qualify for the FIT. The requirement has not been carried forward in SB 32, amending the Existing FIT requirements. It is also not in our existing RPS program (annual bid solicitation), nor is it required in the QF program or as part of the LTPP. We adopt ED's recommendation that the seller need not be a retail customer of the IOU or serve on-site load for consistency with current law and other programs.

The Existing FIT program is capped at 1.5 MW. In this proceeding, we asked parties whether or not to increase the eligible project size from 1.5 MW to 20 MW. At that time, § 399.20 limited the program to projects not more than 1.5 MW, and we adopted that as project size limit. The transaction limit in an excess sales scenario was similarly limited.

In contemplating RAM design, we revisit both the appropriate project size, and the appropriate transaction size. In other words, we examine what size projects can participate in RAM and whether projects larger than 20 MW that offset their onsite load can participate in the RAM by selling their excess power up to a transaction size limit. We conclude that the project and transaction limit be 20 MW of nameplate capacity for projects utilizing either the full/buy sell or the excess sales option. This approach is straightforward and easy to implement, and potentially reduces some of the gaming concerns associated with larger projects breaking up transactions in order to participate in the RAM.

Parties present a wide range of project sizes that should be eligible as part of a new RPS procurement process for small generators. That range varies from retaining the Existing FIT limit of 1.5 MW per project, to an unlimited megawatt size per project. Parties' positions on the appropriate size of the project sometimes depend on whether the price will be fixed in a FIT or subject to a market mechanism, with several parties advocating fixed FIT prices for smaller projects, and market-based pricing for larger projects.

CARE, AreM, SCE, and others, for example, believe project size should remain at 1.5 MW under a fixed price FIT. However, if based on a competitive market price, CARE supports greater than 3 MW but less than 20 MW.64 TURN supports 2 MW for a fixed price FIT,65 or between three and 10 MW if the price is based on an auction.66 Focusing on a fixed price FIT, PG&E and others argue project size should be limited to 3 MW for several reasons, including recognition of the legislature's most recent guidance in SB 32. SDG&E asserts the risk of system impacts on smaller utilities necessitate a 5 MW limit. ED staff and others recommend a must-take FIT for projects up to 10 MW, with utility discretion to take or reject contracts for projects between 10 MW and 20 MW.67

IEP, DRA, Sierra Club, Environmental Council, and others recommend that a streamlined RPS procurement process be available for projects up to 20 MW. GPI and others argue that a must-take FIT should apply to projects larger than 20 MW. GPI prefers a must-take FIT up to at least 60 MW.68 CEERT says it would eventually "like to see the cap on project size removed so that projects of all sizes may be eligible for the must-take FIT program."69 LA Community College District does not support a project size cap, believing a FIT should be available to any size project.70

For all projects, whether utilizing the full/buy sell or excess sales option, we adopt a project size limit of 20 MW. We do this as part of our goal to streamline the entire RPS program for smaller RPS generators where feasible and reasonable. This can be done here for projects up to 20 MW. We adopt this limit for many reasons.

The California Energy Commission (CEC) has repeatedly recommended that we study and implement a FIT for projects up to 20 MW.71 A 20 MW size limit is also consistent with Commission decisions. We have established certain contract provisions for small sellers because we have found it is difficult for them to bid into a utility request for proposal, and they generally do not have the resources or expertise to negotiate and enter into a bilateral contract. We define the size of those small sellers as 20 MW or less. (See D.07-09-040 at 121).

Several existing programs use a 20 MW threshold and those programs influence our decision here. For example, SCE has a standardized contract program for any project using renewable technology up to 20 MW - its RSC program (see D.09-06-018 at 59). SCE says the RSC program addresses difficulties faced by smaller projects (i.e., those up to 20 MW) when they try to participate in annual RPS solicitations, and eliminates the need for complex negotiations (see D.08-02-008 at 42-4472).

In 2009, PG&E proposed a solicitation as part of its solar PV program for projects up to 20 MW (Application 09-02-019). A 20 MW size potentially has merit in many contexts, and we agree with DRA that PG&E's recommendation that a 10 MW project size limit here is inconsistent with PG&E's proposal for 500 MW of PV installations up to 20 MW for its PV program.73 We recently approved PG&E's PV program for projects up to 20 MW. (See D.10-04-052.)

State law requires electrical corporations to have tariffs and standard contracts for purchases of electricity from certain customers up to 20 MW (See § 2840 et seq. regarding combined heat and power). Federal regulations draw an important distinction between QFs at or below 20 MW and those above 20 MW, including exemptions from the Federal Power Act for the smaller QFs, and certain assumptions about the smaller QFs limited ability to access competitive markets.74 Federal regulations have distinguished between generators at or below 20 MW and those above 20 MW for purposes of interconnection requirements.75

SDG&E and several parties argue for a lower project size limit, asserting that large projects may create significant problems with interconnection, grid system stability, or other concerns. Among other things, SDG&E states:

As project size increases to 5 MW, the probability that system upgrades will be required also increases. As shown in the illustrative example in Attachment A [to SDG&E's terms and conditions Comments], system upgrades that could be required to accommodate projects sized greater than 5 MW would be prohibitively expensive.76

Solar Alliance and Vote Solar counter that prohibitive costs deter developers:

Many of the IOUs' concerns fall by the wayside when one considers SDG&E's acknowledgement (comments at p. 11) that generators are responsible...for interconnection and distribution upgrade costs. In other words, interconnection costs...are likely to be a potent deterrent for developers to interconnect a system beyond what the interconnected distribution system can handle without significant upgrades. This more than adequately addresses SDG&E concern regarding the maximum size limit for projects in SDG&E's service territory. As SDG&E acknowledges (comments at p. 11), `[p]rojects sized above 5 MW are likely to require significant system upgrades...making such projects poor candidates for the FIT Program.'77

We are not convinced that project size must be limited because of system reliability or interconnection cost concerns. Each project, regardless of size, must successfully navigate the interconnection process, including cost allocation, before it can be interconnected. Synchronized operation is not permitted unless and until the system may be operated safely, and projects that will cost too much to interconnect will not be pursued. The evidence demonstrates that existing interconnection requirements adequately address these concerns for all projects, including those 20 MW or less. For all these reasons we find smaller projects, defined here as 20 MW or less, should be eligible for the new RAM procurement program adopted here. IOUs should proposed in their bid protocols how to prevent sellers from breaking up or subdividing larger projects to circumvent the 20 MW project size limit.

PG&E, SCE, and SDG&E must offer Existing FIT customers the choice of selling electricity under an arrangement of either (a) full buy/sell or (b) excess sales (see D.07-07-027 at 33-38. 78) In a full buy/sell transaction, a renewable facility would sell 100% of its generation to the utility. In an excess sales agreement, a facility would first offset its onsite load and sell its excess generation to a utility.

ED proposes that the RAM be available only as a full buy/sell transaction, asserting that the excess sales option fails to provide the IOU with sufficient certainty regarding the expected output from the project and undermines the IOU's ability to conduct long-term procurement planning.79

CalSEIA, SCE, PG&E,80and DRA support the full buy/sell approach. Solar Alliance, IEP, TURN, CEERT, GPI, FuelCell Energy, Sustainable Conservation, SFUI, Redwood Renewables, and Environmental Council support having the option of either (a) excess sales, or (b) the customer having the choice of either full buy/sell or excess.

We are convinced by GPI, TURN, and others that ED's concern is unfounded. GPI correctly contends, for example, that the effect on the integrated electrical system is the same regardless of the type of sale agreement.81 That is, the renewable generator output and the host-site load will exhibit the same levels of variation despite the type of sale arrangement with the IOU, and there is no evidence to show that the output and load are influenced by the type of sales arrangement.82 TURN correctly states that IOUs are capable of reasonably accurate forecasts and have routinely made such calculations in many Commission proceedings. TURN concludes that: "There is no specific reason why providing compensation for net excess sales complicates such forecasts or undermines the accuracy of long-term resource planning."83

Because there is no technological impediment, and because it meets certain state policy goals, we continue the approach of the Existing FIT by allowing the generator to choose either full buy/sell or excess sales. First, the choice of either full buy/sell or excess sales has been available to QFs since 1979. No evidence has been presented that this policy has been unworkable over the last 30 years. Second, in D.07-07-027, we adopted both options for the Existing FIT.84 Thus, we allow both the full buy/sell and excess sales transactions for the RAM. For both types of transactions, the full project capacity should apply to an IOU's capacity cap.

Parties take a wide variety of positions on where a project must be located to be eligible for the RAM - from IOU service territories to the entire CAISO control area. The IOUs support the geographic restrictions of the Existing FIT, wherein generators sell to their interconnecting utility. ED recommends that projects eligible for the RAM program be located within the CAISO control area to facilitate interconnection of projects that efficiently utilize California's distribution and transmission system.

The proposed decision would have allowed any RPS-eligible generator to bid into RAM. That is, all facilities interconnected to the Western Electricity Coordinating Council (WECC) could participate in any of the IOUs' RAM auctions. No parties supported this position.85 Most parties support limiting eligibility to projects located within California, to California's distribution system, or to a utility's service territory. In support of requiring distribution-level interconnection, TURN notes, "The original purpose of the RAM was to provide streamlined market opportunities for distributed generation projects connecting to preferred locations within IOU service territories."86

We agree that RAM eligibility should be limited to the utilities service territories. RAM provides a specific and well-defined value to ratepayers because small system-side RPS projects that connect to utility service territories incur none of the additional costs associated with some other forms of renewable generation. For example, these expenses may include costs to construct new transmission lines for more remote generation facilities and the expense of firming and shaping transactions for generation that can not be delivered directly to a CA balancing authority area. If projects located outside IOU service territories were included in RAM, then the price-only project selection criteria may not be applicable. Instead, IOUs may have to add transmission and/or firming and shaping adders to the market valuation of bids to evaluate the projects on an apples-to-apples basis. Thus, RAM enables more streamlined RPS program administration by requiring bid evaluation based on price only, which does not allow for other qualitative adders which are used to assess and rank bids' value in the annual RPS solicitations.

Accordingly, we will allow any projects located within PG&E's, SCE's, and SDG&E's service territories to participate in RAM and bid into one or more of the IOUs' RAM auctions. If a project is selected in more than one auction, however, it must notify all affected IOUs which one shortlist it will accept within 10 days of its notice that it was selected in multiple auctions.

Finally, we reject a Sierra Club proposal to give community choice aggregators (CCAs) and energy service providers (ESPs) the right of first refusal for electricity from an RPS project in their service areas.87 We seek to promote, not limit, competition. Tipping the scale in favor of CCAs or ESPs would unreasonably constrain the competition upon which this market is premised.

63 Public Utilities Code Section 399.20.

64 CARE Pricing Comments at 4.

65 TURN Pricing Comments at 3.

66 TURN Pricing Comments at 1, assuming SB 32 implementation of a fixed price FIT up to three MW.

67 In this context, must-take means that the IOU must enter into the standard contract to purchase energy from the generator up to various program caps expressed in MW.

68 GPI Terms and Conditions Comments at 5.

69 CEERT Terms and Conditions Comments at 4.

70 LA Community College District Terms and Conditions Comments at 3.

71 See California Energy Commission 2006, 2006 Integrated Energy Policy Report Update, CEC-100-2006-001-CMF, January 2007 at E-6; California Energy Commission 2007, 2007 Integrated Energy Policy Report, CEC-100-2007-008-CMF, January 2008 at 6; California Energy Commission 2008, 2008 Integrated Energy Policy Report Update, CEC-100-2008-008-CMF, November 2008 at 29; California Energy Commission 2009, 2009 Integrated Energy Policy Report, Final Commission Report, December 2009, CEC-100-2009-003-CMF at 230.

72 SCE recently said of its RSC program for projects up to 20 MW: "Through this program, SCE has sought to remove some of the barriers that smaller projects may have had when participating in SCE's annual solicitations. Such barriers have been especially evident for projects with smaller generating capacities. By offering standardized contracts for smaller projects, SCE hopes to increase opportunities for such projects to execute contracts with SCE and contribute to the State's RPS goals." (Advice Letter 2356-E (July 1, 2009) at 3.)

73 DRA Terms and Conditions Reply Comments at 7.

74 18 CFR 292.309(d)(1) establishes a rebuttable presumption that a QF with capacity at or below 20 MW does not have nondiscriminatory access to the wholesale electricity market. Also see 18 CFR 292.601 regarding certain exemptions from federal and state law for QFs at or below 20 MW.

75 For example, see SCE 2009 RPS Procurement Plan Request for Proposals at Section 7.04.

76 Terms and Conditions Comments at 5-6.

77 Joint Terms and Conditions Reply Comments at 3.

78 The other four utilities (PacifiCorp, Sierra, Mountain Utilities, Bear Valley) must offer to purchase pursuant to full buy/sell, and may offer to purchase via excess sales.

79 March 2009 Proposal at 9.

80 PG&E supported the excess sales option in the March 2009 Proposal, but changed its position to supporting the full buy/sell option in its comments on the proposed decision.

81 Integrated system planning, for example, can be successfully performed whether electricity generation is on the "customer side" or the "utility side" of the meter.

82 Terms and Conditions Comments at 3.

83 Terms and Conditions Comments at 6.

84 We dismissed SCE's application for rehearing of D.07-07-027 on this subject. In doing so, we concluded that the two sales options are consistent with the plain language of the FIT statute. We also said that the two options further the statutory intent of promoting reasonable development of renewable resources to meet multiple state objectives. The two sales options continue to do so, and should be adopted in the RAM to facilitate the same objectives.

85 Specifically, Axio, DRA, CARE, FCE, FIT Coalition, enXco, Recurrent, SFUI, SDGE, Solar Alliance, and TURN oppose a WECC-wide approach.

86 TURN Comments on PD at 7.

87 Terms and Conditions Comments at 12.

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