Next, we must address issues surrounding the treatment of RECs arising from net surplus generation. AB 920 provides that the utilities that purchase net surplus generation shall receive the RECs associated with such generation and that the electricity purchased shall count toward their RPS targets, consistent with the RPS statutes. Specifically, Section 2827(h)(5) states:
(5)(A) Upon adoption of the net surplus electricity compensation rate by the [Commission], any renewable energy credit, as defined in Section 399.12, for net surplus electricity purchased by the electric utility shall belong to the electric utility. Any renewable energy credit associated with electricity generated by the eligible customer-generator that is utilized by the eligible customer-generator shall remain the property of the eligible customer-generator.
(B) Upon adoption of the net surplus electricity compensation rate by the [Commission], the net surplus electricity purchased by the electric utility shall count toward the electric utility's renewables portfolio standard annual procurement targets for the purposes of paragraph (1) of subdivision (b) of Section 399.15, ....
Section 399.12 defines a REC as "a certificate of proof, issued through the accounting system established by the [CEC] pursuant to Section 399.13, that one unit of electricity was generated and delivered by an eligible renewable energy resource." Section 399.13 confers upon the CEC the authority to certify eligible renewable energy resources, to design and implement an accounting system to verify compliance with RPS by retail sellers, to ensure electricity generated by renewable energy resources is only counted once, and to establish a system for tracking RECs. Currently, in order to qualify for RPS compliance, renewable energy generators must be certified as eligible by the CEC, and the REC must be tracked and verified in WREGIS, which requires the meter measuring the generation to have accuracy of plus or minus two percent. At this time, almost no DG is RPS-eligible, except DG systems under AB 1969 tariffs,23 and it is unclear whether systems on net metering tariffs have meters that comply with WREGIS accuracy requirements. The CEC will determine the eligibility of customer-side DG for the RPS and the system for tracking RECs from these resources. This will likely occur through revisions to its RPS Eligibility Guidebook.
Given these factors, we must now discuss the mechanics of how any RECs from net surplus generation may be counted by the utilities as well as whether and how much to compensate net surplus generators for the renewable attributes of their electricity.
6.1. RPS Eligibility, Meter and Tracking Requirements
Several parties, namely PG&E, SCE, the Joint Solar Parties, CALSEIA/EC, IREC, the City of San Diego and DRA, suggest that in order to implement AB 920, the Commission can ignore the RPS statutes, essentially Sections 399.12 and 399.13, which mandate CEC RPS eligibility and WREGIS metering and registration requirements. These parties contend that AB 920 expressly intends for the utilities to receive RECs from net surplus generation and count them toward their RPS annual procurement targets, and that CEC certification and WREGIS metering requirements are not necessary preconditions for this to occur. According to SCE, AB 920 should be construed in a simple fashion to facilitate utility purchases of renewable attributes from NEM customers. SCE recommends a "carve-out" arrangement, where net surplus generation purchased by the utilities under AB 920 would not have to be tracked in WREGIS or meet CEC RPS eligibility requirements in order to be counted towards utility RPS targets.
PG&E and others claim it would be complex and expensive for customers to obtain RPS certification and register with WREGIS. Further, if customers have sold their RECs to a third party through a Power Purchase Agreement, it will be impractical and costly for PG&E to obtain ownership declarations from each customer. These parties contend the simple and cost-effective approach is to allow customers with net surplus generation to receive compensation for the renewable attributes of their excess generation, and for the utilities to get RPS credit for the generation, whether or not the facility is certified as RPS-eligible by the CEC, whether or not the facility generates a REC that is tracked through WREGIS, and whether or not the NEM customer actually owns the REC.
We disagree with these parties' suggestion that the language of AB 920 replaces RPS certification and tracking requirements and allows us to ignore existing statutes that confer authority upon the CEC to set RPS eligibility and verification requirements. AB 920 does not repeal RPS statutes, and the language of Section 2827(h)(5)(A) specifically references RECs as defined in Section 399.12. Section 399.12 further references 399.13. Thus, we conclude that Sections 2827(h)(5)(A) and (B) must be harmonized with existing RPS statutes. SDG&E and Sierra Pacific presented this logic and we agree. We find that although the statute states that any RECs for net surplus electricity purchased by the utility shall belong to the utility, we find that when AB 920 is read in concert with the RPS program statutory framework, certain prerequisites must be met before the renewable energy associated with net surplus generation can be counted toward RPS compliance goals. We conclude that net surplus generation purchased by the utility cannot be counted for RPS purposes unless it first meets the preconditions of CEC certification as RPS-eligible and CEC REC tracking and certification requirements.
Moreover, we agree there are unresolved issues related to accounting for split ownership of RECs. According to Section 2827(h)(5)(A), any REC for net surplus electricity purchased by the electric utility shall belong to the electric utility, while any REC associated with electricity generated by the eligible customer-generator and used by the eligible customer-generator remains the property of the eligible customer-generator. It is unclear whether WREGIS or another CEC-approved system can track and otherwise account for RECs that would be split between the utility and the customer in such a fashion. In addition, RECs for RPS compliance are accounted for in 1 megawatt-hour (MWh) increments and it is unclear if the utilities or another entity may aggregate the net surplus generation of multiple small NEM customers to create RECs in the appropriate 1 MWh increments.
SDG&E proposes that stakeholders should collaborate to develop a streamlined process for NEM customers to obtain RPS certification from the CEC and meet WREGIS accounting requirements. We agree. If the utilities want the ability to count RECs from net surplus generation toward RPS, they and other parties, should work with the CEC through its process for revising its RPS Eligibility Guidebook to have RPS certification and accounting requirements, including split ownership of RECs and aggregation, dealt with by the CEC and WREGIS or some other tracking system.24
In summary, we find that the utilities cannot count net surplus generation obtained from NEM customers toward RPS procurement targets until NEM customer facilities are CEC certified and their RECs are tracked through a CEC-approved system. This is critical to ensure that net surplus generators retain the rights to the renewable attributes of their power and that any RECs produced by net surplus generators are not double-counted (i.e., used for RPS compliance and also used in a voluntary REC program). Once NEM net surplus generators are deemed RPS-eligible by the CEC and their net surplus generation is appropriately accounted for, including REC splitting and aggregation, the utilities may then count RECs for RPS purposes. Similarly, the NEM customer should not be compensated for the renewable attributes of electricity in the form of RECs until such time as they actually create RECs and make them available to the utility. Once that occurs, the NSC rate can include a value for renewable attributes, which we discuss below in Section 6.3.
A related issue is whether utilities may retroactively count net surplus generation toward their RPS procurement targets and retroactively compensate the renewable attributes of any net surplus generation that occurred prior to the CEC establishing RPS certification and REC tracking requirements for net surplus generation. NEM customers may have signed up for net surplus compensation as early as January 2010 and may expect compensation for the renewable attributes of their power from that date. We assume that because Section 2827(h)(3) directs that a customer's 12 month true-up period for net surplus compensation begins when the utility receives the eligible customer-generator's election, the CEC may establish a process that allows net surplus generators to retroactively certify their generation facilities to the beginning of their 12 month true-up period. In the event the CEC authorizes retroactive certification, the utilities may apply net surplus generation that occurred prior to CEC certification toward their RPS targets and compensate the renewable attributes of this net surplus generation, provided that the RECs are also transferred to the purchasing utility.
6.2. What if customers have sold their RECs to a third party?
Another concern is whether NEM customers need to certify that they own the RECs associated with their power in order for the utility to compensate the NEM customer for the RECs and count them towards RPS targets. PG&E contends that customers should not be required to prove REC ownership to receive compensation for net surplus generation. The remaining utilities, Acton, IREC, CALSEIA/EC, City of San Diego, and the Joint Solar Parties recommend that customers should only receive payment for renewable attributes if they affirm ownership of the REC. They suggest that if a customer has sold its RECs, the utility should be allowed to pay a lower, or "brown power price," for the net surplus generation without RECs. The Joint Solar Parties suggest that only larger customers with systems 100 kW and above should be required to provide an affidavit they have not sold or transferred the RECs to another entity as a condition of receiving full NSC. PG&E concedes it may be appropriate for larger customers 500 kW or greater to certify they own their RECs. CALSEIA/EC proposes that the utilities should be required to identify those customers under third-party ownership arrangements who may have assigned RECs to third party owners.
The statute is clear that "any [RECs]... for net surplus electricity purchased by the electric utility shall belong to the electric utility." (Section 2827(h)(5)(A).) We have found above that in order for the utilities to receive RECs from net surplus generation and count them toward RPS requirements, NEM customers must meet CEC RPS certification and REC metering and tracking requirements. Similarly, we find that any NEM customer seeking NSC payments for the renewable attributes of its generation must certify it owns the RECs associated with its generating facility. We will require the utilities to obtain certification of REC ownership from all NEM customers prior to compensating them for any renewable attributes or counting any RECs created by net surplus generators toward RPS procurement targets.
6.3. Value of renewable attributes
We now turn to the question of whether to include payment for the value of the renewable attributes of electricity in the NSC rate. Again, the statute does not mandate compensation for the value of renewable attributes, but allows the Commission to determine if appropriate justification exists for such compensation.
A quick recap of the proposals for pricing renewable attributes is in order. The utilities generally suggest establishing a value for renewable attributes separate from the value of electricity. Specifically, SCE proposes a proxy value based on renewable premiums from voluntary green energy programs as reported by utilities within the WECC and published by the DOE. SCE calculates this renewable premium at 1.83 cents per kWh based on current published data. PG&E and SDG&E both suggest that once REC trading is in place in California, renewable attributes could be priced using the average REC price over a 12-month period.25 In the interim period prior to REC trading, SDG&E suggests adding the MPR GHG adder of 0.8 cents/kWh to the electricity portion of the NSC rate if the renewable energy that is purchased is RPS-eligible. PacifiCorp proposes an adder of one cent/kWh.
CALSEIA/EC, the Joint Solar Parties, Acton, and City of San Diego do not suggest a separate value for renewable attributes because they propose a bundled rate, based on either retail rates, feed-in tariff rates, the MPR, contract prices under RPS, or utility-owned solar prices. The bundled rate proposals include compensation for both electricity and renewable attributes. Similar to the utility proposals, the Joint Solar Parties suggest that once a REC price is established by a market, that price could be substituted for the GHG adder currently embedded in the MPR. Sierra Pacific proposes no compensation for renewable attributes because it maintains NEM customers are not RPS-eligible or tracked by WREGIS.
CARE provides no estimated value for renewable attributes, although it maintains that GHG offsets in the form of RECs are an energy ancillary service that the Commission maintains authority over in regard to the price that is paid to QFs. CARE contends the implied REC price is the difference between the cost of the standard contract and the market value of a comparable brown energy product. PG&E claims CARE's comments contain incorrect statements regarding FERC jurisdiction and there is no foundation for CARE's argument that a REC or a GHG offset are similar to ancillary services.
RECs are the appropriate measure of a generator's renewable attributes and we believe that it is appropriate to compensate NEM customers for RECs conveyed to the utility with excess generation, separate from the compensation for their electricity. However, in keeping with our findings above that NEM surplus generators must meet CEC RPS eligibility and REC metering and tracking requirements, and that RECs are not created until those conditions occur, payment for renewable attributes cannot occur until the CEC determines whether net surplus generation by NEM customers is RPS-eligible and the CEC completes its work to establish a REC ownership verification and tracking process for DG facilities.
Once that work by the CEC is complete, we find it reasonable to add the renewable premium proposed by SCE to the DLAP-based NSC rate described in Section 5, as an interim measure. We adopt this renewable adder as a placeholder for the renewable value of net surplus generation until RECs are publicly-traded. This renewable proxy price is not derived from RECs procured by California's RPS-obligated retail sellers. We find this renewable proxy reasonable only for the narrow and unique circumstance of net surplus generation by NEM customers, which has no capacity value and is provided without contract on an intermittent, unpredictable, and as-available basis over a 12-month period. Therefore, we adopt SCE's proposal to use the most recent WECC average renewable premium, based on DOE published data, as an interim proxy value for the renewable attributes of net surplus generation. SCE calculated this premium at 1.83 cents per kWh, but the utilities should use the most recent DOE published data and SCE's calculation methodology to update this rate when filing their NSC tariffs in compliance with this decision. Again, this interim renewable premium will only be added to the DLAP-based NSC after the CEC certifies NEM facilities as RPS-eligible and establishes an ownership verification and tracking process for any RECs associated with net surplus generation.
We adopt the SCE approach as an interim renewable value because ultimately, we prefer a market-based valuation for the renewable attributes of net surplus generation. Conceptually, we agree with proposals by PG&E, SDG&E and the Joint Solar Parties to value renewable attributes based on the average REC price over a 12-month period once RECs are traded, although this will require a means to obtain public REC prices. Therefore, we will reconsider the appropriate value for renewable attributes once public information on REC prices in California is available. Parties may file a petition for modification of this decision once net surplus generators meet CEC RPS eligibility requirements, their RECs are tracked through a CEC-approved process, and REC trading provides new information on renewable prices. If such a petition is filed, it should, among other things, supply new information for the Commission to consider in the valuation of the renewable attributes of net surplus generation. Any petition should also address the process by which all customers will certify to their REC ownership prior to receiving compensation.
23 The RPS Eligibility Guidebook (3d ed., December 2007) (available at http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-ED3-CMF.PDF) explains that:
The Energy Commission will not certify distributed generation PV and other forms of customer-sited renewable energy into the RPS at this time, with the following exception.
The Energy Commission will certify facilities that would have been considered distributed generation facilities except that they are participating in a standard contract/tariff executed pursuant to Public Utilities Code § 399.20, as implemented through the CPUC Decision 07-07-027 (R.06.05.027), executed pursuant to a comparable standard contract/tariff approved by a local publicly owned electric utility. . ., or if the facility is owned by a utility and meets other requirements, to become certified as RPS-eligible . . . .
The Energy Commission will not certify distributed generation facilities as RPS-eligible unless the CPUC authorizes tradable RECs to be applied toward the RPS. (RPS Eligibility Guidebook at 18.)
24 As a practical matter, the quantity of NSC generation available to be considered towards the RPS program goals is de minimus compared to the utility RPS targets. For example, in 2009, the RPS procurement target for PG&E was 11,623 GWh (see PUC RPS Quarterly Report to Legislature, 2010 Quarter 2," Table 1 at 4), while PG&E reports its excess generation from NEM customers in 2009 was 5,212,073 kWh (5.2 GWh), or approximately 0.04% of the annual RPS target.
25 There is currently no functionality in WREGIS to post a public REC price.