3. Discussion

3.1. Legislative Background

The RPS program has been the subject of much legislation and many decisions by this Commission.6 Most recently, Senate Bill (SB) 2 (1X) (Simitian), stats. 2011, ch. 1 was enacted in the First Extraordinary Session of the Legislature.7 SB 2 (1X) is effective December 10, 2011, the 91st day after the end of the special session in which it was enacted.8

SB 2 (1X) makes numerous changes to the RPS program, most notably extending the RPS goal from 20% of retail sales of all California IOUs, electric service providers (ESPs), and community choice aggregators (CCAs) by the end of 2010, to 33% of retail sales of IOUs, ESPs, CCAs and publicly owned utilities by the end of 2020.9 SB 2 (1X) also modifies or changes many details of the RPS program, including creating portfolio content categories for RPS procurement.

3.2. Plan of this Decision

This decision is one of several decisions that will be needed to implement the complex provisions of SB 2 (1X). This decision focuses on new § 399.16, which establishes three new portfolio content categories for RPS procurement and sets minimum and maximum use of procurement in each category.10 This decision proceeds largely in the same order as the statutory sections, although some issues are addressed out of chronological order, when they logically first appear. Consideration of some statutory provisions is deferred to later decisions where they may be grouped with other provisions presenting similar issues.

Because SB 2 (1X) became effective December 10, 2011, provisions of the RPS statute in effect prior to that time are referred to in this decision as "prior" provisions or sections; provisions of SB 2 (1X) are referred to as "new" or without modification.

Since the principal task of this decision is implementing new statutory provisions, the decision is guided by the basic principles of statutory construction. The California Supreme Court has enunciated clear standards for courts or agencies construing a statute. The Commission must:

... look to the statute's words and give them their usual and ordinary

meaning. The statute's plain meaning controls the court's interpretation unless its words are ambiguous. If the statutory language permits more than one reasonable interpretation, courts may consider other aids, such as the statute's purpose, legislative history, and public policy. . . .

Where more than one statutory construction is arguably possible, our policy has long been to favor the construction that leads to the more reasonable result. This policy derives largely from the presumption that the Legislature intends reasonable results consistent with the apparent purpose of the legislation.11

Although the courts remain the ultimate arbiters of statutory meaning, they accord deference to the Commission's reasonable interpretation of statutes. (Greyhound Lines, Inc. v. Public Utilities Commission (1968) 68 Cal.2d 406, 410; Lockyer v. City and County of San Francisco (2004) 33 Cal.4th 1055, 1090-1091.)

This decision also of necessity sets basic parameters for some of the administrative processes necessary to implement the new statutory requirements. Because retail sellers have ongoing RPS procurement and compliance obligations, practical questions such as what information IOUs must provide in their advice letters and how compliance with the portfolio content requirements can be shown must be addressed in the near term, though issues will continue to arise and require resolution as implementation of SB 2 (1X) proceeds.12 The Commission's approach to these regulatory issues is outlined as it applies to each portfolio content category.

Finally, some topics that are not presented in the text of new section 399.16, but are necessary to the implementation of the new provisions, are also addressed, such as the former requirement for "delivery" of RPS-eligible resources to California.

3.3. Upfront Showings and Compliance Determinations

As will become evident from the discussion below, implementing the new portfolio content categories will require all participants in California's RPS market to acquire and provide more information about their transactions than has been needed previously. The additional information is necessary for both an "upfront showing" when an IOU seeks Commission approval of an RPS procurement contract, and to inform a subsequent "compliance determination" by this Commission as to the appropriate portfolio content category of RPS procurement by all retail sellers.

Many sources of information about important elements of RPS procurement transactions exist, providing different types of information.13 These sources start with the RPS procurement contract itself, which typically provides information about the generation facility, interconnection, transmission rights, scheduling plans, and (in all likelihood) the intended portfolio content category classification of the procurement under the contract. The basic contract may be augmented by additional agreements for dynamic transfer or firming and shaping, as discussed below.

There are also several sources of information about the electricity generated. At the RPS-eligible generation facility itself, the generation meter provides data about actual electricity generated. E-Tags can include a wide range of information, including identifying the renewable generation facility, the buyer and seller in the schedule, physical transmission path, date and hour of the schedule, and megawatt-hours (MWh) of electricity scheduled. The Western Renewable Generation Information System (WREGIS) compiles facility generation data on a monthly basis and has recently added a functionality to match WREGIS Certificates14 with e-Tag information about electricity generated outside a California balancing authority and scheduled into a California balancing authority.15

Retail sellers should expect to provide information to Energy Division staff from any or all of these sources in order to meet the requirements of new  § 399.16, and, more broadly, the increased information requirements associated with SB 2 (1X) as a whole.

3.3.1. Upfront Showing in IOUs' Advice Letters

In furtherance of the Commission's responsibility to ensure just and reasonable rates and to protect ratepayers from unreasonable costs, including those that may arise from RPS procurement, IOUs16 will be required to make an upfront showing related to the categorization of each proposed RPS procurement transaction. Because this Commission is not responsible for the rates of ESPs and CCAs, and does not review their RPS contracts, the requirements for the upfront showings set forth in this decision do not apply to those retail sellers. (D.11-01-026 at 19; D.07-11-025 at 26.) The implementation of the Commission's responsibility to protect IOU ratepayers, however, does not alter the statutory requirements for the portfolio content categories themselves, which apply equally to all retail sellers.

The upfront showing in an IOU's advice letter must be sufficiently detailed and reliable to justify a finding that the IOU may recover its costs for the contract. All parties agree that the minimum and maximum procurement percentages of procurement content categories set out in § 399.16(c) are likely to result in different market values for procurement meeting the criteria of different categories.17 Thus, in order to evaluate the reasonableness of the costs of a contract presented for Commission approval, the proposed portfolio content category of the procurement must be documented and analyzed.18

SDG&E urges that cost recovery expressly be allowed even if the procurement turns out, when the compliance determination is made by Commission staff, not to meet the criteria of the portfolio content category that the IOU initially presented in the advice letter. SDG&E's position is reasonable, but only if enough information is presented with the advice letter for the Commission to be reasonably sure that the portfolio content category of the proposed contract is correctly characterized. This is likely to require that the IOUs provide comprehensive information in their advice letters seeking approval of RPS procurement contracts, so that the Commission and stakeholders may assess the risks involved with the contract and the range of value to ratepayers the contract may provide. The Director of Energy Division is authorized to develop, in consultation with the parties, formats and information requirements for advice letters for RPS procurement that will facilitate evaluation of the proposed procurement in light of the Commission's implementation of the new portfolio content categories in SB 2 (1X).

3.3.2. Compliance Determinations for All Retail Sellers

When a retail seller claims RPS procurement for a particular portfolio content category, Commission staff must determine whether the procurement in fact complies with the requirements of the portfolio content category for which it is claimed. This determination by the Commission of conformity with criteria for a specific RPS portfolio content category is different from the Commission's enforcement of the overall RPS procurement quantity requirements set in D.11-12-020, implementing §§ 399.15(b)(1), (2). The Commission's enforcement of RPS procurement quantity requirements is based on the CEC-verified total RPS-eligible procurement of each retail seller. (D.06-10-050) The Commission determines compliance with specific RPS procurement requirements (e.g., portfolio content categories (§ 399.16(b)); portfolio content category usage limits (§ 399.16(c)); requirements for use of short-term contracts (D.07-05-028; see also § 399.13(b)) based on the compliance reports and supporting information provided by each retail seller. (D.06-10-050; see also § 399.13(a)(3).)19

In order for Energy Division staff to make an effective compliance determination on procurement claimed by a retail seller for a particular portfolio content category, all retail sellers must provide to Energy Division staff documentation adequate to demonstrate that the retail sellers' procurement in fact meets the criteria of the portfolio content category in which the procurement is claimed. For those categories in which multiple criteria must be satisfied, the retail seller's showing for the compliance determination must meet all relevant criteria set forth by the statute and implemented in this decision.

Although ESPs and CCAs are not required to make upfront showings of the potential portfolio content category of their planned procurement, all retail sellers must maintain documentation from the inception of a procurement contract to its conclusion.20 In making its compliance determinations, Commission staff should be able to review the entire course of an RPS procurement transaction.

The upfront showing by IOUs in their advice letters and the compliance determinations for all retail sellers will be important components of the administration of the portfolio content categories. It is likely that modifications to Energy Division's current advice letter template and RPS compliance spreadsheet will be required. The complete requirements will be developed through further decisions and by Energy Division staff in consultation with the parties. In this decision, preliminary-but real-direction is given to retail sellers and Energy Division staff on how to structure such showings and determinations.21

3.4. Repeal of "Delivery" Requirement for RPS Eligibility

SB 107 set certain requirements for the RPS eligibility of generation facilities and generation, including a requirement that electricity must be "delivered" in order to be RPS-eligible.22 SB 2 (1X) eliminates the "delivery" requirement for RPS eligibility by amending Pub. Res. Code § 25471 to remove the references to delivery.23 CEC is responsible for administering both the current and the new RPS eligibility requirements. (§ 399.25.) The CEC's implementation of the RPS eligibility rules is set forth in its Renewables Portfolio Standard Eligibility Guidebook (Eligibility Guidebook).24

Under the "delivery" rules, Commission approval of a utility's RPS procurement transaction with RPS-eligible generators interconnected to the Western Electricity Coordinating Council (WECC) transmission system outside California requires documentation that the CEC has reviewed the structure of the transaction and decided that it meets the "delivery" requirement for RPS eligibility. (See, e.g., Resolution (Res.) E-4390, Appendix A.) This requirement must change, since it is based on the SB 107 "delivery" requirement.

Some parties argue that the repeal of the "delivery" requirement for RPS eligibility is effective as soon as SB 2 (1X) is effective.25 Others assert that the "delivery" requirement remains in effect until the CEC removes it from the Eligibility Guidebook.26 Although it is true that the CEC's Eligibility Guidebook provides guidance for how to meet the "delivery" requirement and for verification that it has been met, the legal requirement for "delivery" as provided by SB 107 ceases to exist once its repeal by SB 2 (1X) goes into effect on December 10, 2011. Therefore, independent of the CEC's Eligibility Guidebook, this Commission's authority to require a demonstration that an RPS procurement transaction filed for review by the Commission meets the "delivery" requirement ends when the repeal goes into effect.27

TURN and SCE suggest that this change to the RPS eligibility requirements allows parties (i.e., buyers and sellers) to RPS contracts approved by the Commission prior to December 10, 2011 to ignore or cease to enforce the delivery provisions in those contracts. Other parties assert that contracts approved by the Commission prior to December 10, 2011 should not be affected by the elimination of the delivery requirement.28

The statutory change, without more, does not alter a contract approved by the Commission. The terms and conditions of any RPS contract approved by the Commission remain in effect, including the delivery requirements, unless and until amended by the parties. Because any change to the approved delivery structure may have value and price implications for ratepayers, the IOUs must submit any such amendments for approval by the Commission. Any contract amendments changing the delivery structure approved under the prior "delivery" requirement may be submitted directly to the Commission, without needing prior CEC approval, at any time after December 10, 2011.

The Commission does not review or approve the RPS procurement contracts of ESPs and CCAs. Accordingly, changes to the delivery structure in their contracts may also be made without Commission review. If, after December 10, 2011, an ESP or a CCA makes changes to a contractual delivery structure set up prior to that date, it must be prepared to present documentation and explanation of the changes if requested to do so by Energy Division staff to facilitate a compliance determination.

The impact of the repeal of the "delivery" requirement for RPS eligibility on the new portfolio content categories is discussed more fully below.

3.5. Section 399.16(b): RPS Portfolio Content Categories

The three portfolio content categories created by SB 2 (1X) are set out in new § 399.16(b). These new portfolio content categories apply to RPS-eligible generation associated with RPS procurement contracts or ownership agreements signed after June 1, 2010 and, by necessary implication, to RPS-eligible generation from utility-owned generation facilities (UOG) with an online date after June 1, 2010.29 Each category includes criteria by which inclusion in the category is to be evaluated. The categories apply in terms to "eligible renewable energy resource electricity products" that meet the criteria for one of the categories. In response to the Ruling, parties propose a variety of interpretations of this phrase, some focusing on the procurement transaction;30 some focusing on the generation source;31 some on how the electricity products should be delivered to a retail seller;32 and some on the products themselves.33

Examining these proposals leads to the conclusion that the phrase "eligible renewable energy resource electricity products" describes the analytically important elements of each portfolio content category. As long as the portfolio content criteria are understood to apply to RPS-eligible generators and generation (as all parties agree), the "product" is simply "that which meets the criteria for this category or subcategory."34 One RPS procurement contract can thus either sell one "product," or provide for the sale of different "products" meeting different portfolio content category criteria, as long as the criteria are clearly differentiated and the information necessary for Energy Division staff's evaluation of IOUs' contracts (including upfront showing of portfolio content category and pricing in formation) is provided.

3.5.1. Section 399.16(b)(1): Interconnected to a California Balancing Authority, Scheduled Without Substitution, and Dynamically Transferred Energy

Procurement in this first portfolio content category is intended to constitute the majority of new RPS procurement through 2020 and beyond. (See § 399.16(c), discussed more fully below.) Parties have identified three separate criteria within § 399.16(b)(1)(A), in addition to the separate criterion set out in § 399.16(b)(1)(B).35

Section 399.16(b)(1)(a) sets out:

(A) Have a first point of interconnection with a California balancing authority, have a first point of interconnection with distribution facilities used to serve end users within a California balancing authority area, or are scheduled from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source. The use of another source to provide real-time ancillary services required to maintain an hourly or subhourly import schedule into a California balancing authority shall be permitted, but only the fraction of the schedule actually generated by the eligible renewable energy resource shall count toward this portfolio content category. . . .

Each of the three criteria in this part of § 399.16(b)(1) refers to "a California balancing authority." As defined in § 399.12(d), this term requires that such a California balancing authority has "control over a balancing authority area primarily located in this state." (Emphasis added.)36 The simplest method of determining whether a balancing authority area is primarily located in California is, as most parties suggest, whether more than 50% of the load served by the balancing authority is located within the political boundaries of California.37 Five balancing authorities currently meet this test: California Independent System Operator (CAISO), Balancing Authority of Northern California (formerly SMUD), Imperial Irrigation District, LADWP, and Turlock Irrigation District.38

Some parties urge that a mechanism be set up now to allow other balancing authorities to qualify as "California balancing authorities" under the test enunciated in this decision at some time in the future, and to mange the consequences of a balancing authority no longer meeting the "California balancing authority" requirements. This is not a priority task in this initial stage of implementing SB 2 (1X). The Director of Energy Division is authorized to develop a method for making these determinations if it appears to be necessary in the future.

The first substantive criterion in section 399.16(b)(1)(A) is that the RPS-eligible generator must "[h]ave a first point of interconnection with a California balancing authority." The first point of interconnection to the WECC is the substation or other facility where generation tie lines from a given power plant interconnect to network transmission within the Western Interconnection.39 Thus, if the first point of interconnection for an RPS-eligible generation facility, as so defined, is within the metered bounds of a California balancing authority, this criterion is met.

The second criterion is that the RPS-eligible generator must "have a first point of interconnection with distribution facilities used to serve end users within a California balancing authority area." This criterion distinguishes interconnection at the distribution level from interconnection at the transmission level.

It is important to note that generation from renewable sources (e.g., solar photovoltaics) that are on the customer side of the meter and interconnect to the distribution system has historically not been certified as RPS-eligible, with the limited exception of customer-side distributed generation (DG) participating in an IOU tariff pursuant to prior § 399.20, as implemented by D.07-07-027.40 In the Draft Eligibility Guidebook, CEC staff proposes that any customer-side DG may be certified as RPS-eligible, so long as it uses an RPS-eligible source of generation and meets all other eligibility requirements established by the CEC, including participating in WREGIS and using a meter that reports generation with an accuracy rating of two percent or higher accuracy.41 Until the CEC adopts new certification criteria and procedures for customer-side DG, the existing restriction of RPS-eligibility to customer-side DG installations participating in tariffs under D.07-07-027 remains in place.

The third criterion in section 399.16(b)(1)(A) requires that the electricity produced by an RPS-eligible generation facility must be:

scheduled from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source. The use of another source to provide real-time ancillary services required to maintain an hourly or subhourly import schedule into a California balancing authority shall be permitted, but only the fraction of the schedule actually generated by the eligible renewable energy resource shall count toward this portfolio content category.

As GPI observes, this criterion is more restrictive than the prior "delivery" requirement. Compare the text above with the Eligibility Guidebook at 37, n.61 (4th ed. Jan. 2011).

This criterion contains several components that make it more complex than the other criteria in § 399.16(b)(1), as TURN, PG&E, and SCE point out. These components include:

· without substituting electricity from another source

· real-time ancillary services

· hourly or subhourly import schedule

· fraction of the schedule generated by the RPS-eligible generator

Parties agree that the transmission schedule from the RPS-eligible generator into a California balancing authority must be hourly. If, as UCS, NextEra, and Sempra suggest, subhourly scheduling of RPS-eligible electricity into California balancing authorities becomes common, this section will be unaffected, since subhourly scheduling is necessarily included within hourly. The statute also specifies that the hourly or subhourly schedule is an "import" schedule. The necessary implication of this language is that the electricity is generated outside the metered boundaries of a California balancing authority.

"Real-time ancillary services," which are permitted under the statute if needed to "maintain an hourly or subhourly import schedule," are different from substitute energy. Real-time ancillary services are typically provided by the host balancing authority (i.e., the balancing authority where the RPS-eligible generator is interconnected) to maintain the import schedule if variations occur on an hourly or subhourly basis.42 Unlike substitute electricity, the ancillary services are not the electricity that is actually scheduled.

The core substantive requirement within these criteria is that the electricity must be scheduled "from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source." That is, the schedule must be from the RPS-eligible generator, not from "another source" providing generation that will actually be used in place of ("substituting" for) the RPS-eligible generator's output to meet the schedule.43 Parties disagree about whether scheduling electricity from an RPS-eligible generation facility that is not the RPS-eligible generator with whom the retail seller has a procurement contract meets the criteria for this category.44 Although parties urging the acceptance of such scheduling in this category provide plausible policy reasons for their proposal, it is not supported by the statutory language. The language plainly says, "without substituting electricity from another source." It does not say, "another non-renewable source."45

By stipulating that "only the fraction of the schedule actually generated by the eligible renewable energy resource shall count toward this portfolio content category," the statute provides that real-time ancillary services may not be counted toward the retail seller's RPS compliance requirements. Reprising the argument about third-party renewable resources, some parties argue that ancillary services sourced from RPS-eligible resources should not be subtracted from the scheduled amount of generation that is ultimately imported. The statutory text does not support this view. Analogously to the proscription of substitute energy from "another source," this component directs that only the fraction of the schedule generated by the RPS-eligible generator may count. That is, the fraction of the schedule generated by the RPS-eligible generator with which the retail seller has a procurement contract is what counts for RPS compliance.

Some parties seek to allow electricity from on-site storage of an RPS-eligible generator's own generation to be counted in this portfolio content category.46 This effort appears to be unnecessary. If the RPS-eligible generator with on-site storage has its first point of interconnection within a California balancing authority, all of its output to meet its contract (however characterized) would count toward this category. If the RPS-eligible generator does not have its first point of interconnection within a California balancing authority, but adds electricity from its own storage to meet its schedule, then the electricity is not from "another source" and no (or fewer) real-time ancillary services are needed to maintain the schedule, and thus are not subtracted from the "fraction of the schedule actually generated by the eligible renewable generation resource."

Another issue in the interpretation of this criterion is whether firm transmission rights are necessary in order to ensure that the RPS-eligible energy is "scheduled from the eligible renewable energy resource into a California balancing authority without substituting electricity from another source." The Commission first looked at firm transmission in the RPS context in D.10-03-021. Following on that decision, the ruling asked parties to comment on the role of firm transmission in the new portfolio content categories.

As AReM, enXco, PG&E, and UCS point out, the statutory procurement structure provided by § 399.16 is different from that of D.10-03-021. Parties are in agreement that holding firm transmission rights is not a necessary element of meeting the new criterion of scheduling into a California balancing authority without substituting electricity from another source.

However, a transaction that includes firm transmission may provide greater certainty and value. As Davenport, enXco, and Powerex point out, it is commercially advantageous for a generation facility to have firm transmission rights when negotiating the terms of the sale of its RPS-eligible energy to a California retail seller, since the likelihood of curtailment due to transmission constraints is substantially reduced. In an IOU's upfront showing, firm transmission is likely to have an impact on the likelihood that the procurement will ultimately meet the criteria for § 399.16(b)(1). With respect to a compliance determination, the existence of a firm transmission arrangement may simplify the retail seller's task in showing that procurement claimed to meet this criterion actually did so, and may simplify the task of Energy Division staff in evaluating such claims.

In view of the new requirements of the portfolio content categories and particularly the criterion of scheduling into a California balancing authority without substituting energy from another source, further development of the role of firm transmission in classifying RPS procurement, discussed in D.10-03-021, as modified by D.11-01-025, is no longer necessary. The Commission's direction to Energy Division, in Ordering Paragraph (OP) 26 of D.10-03-021, to investigate and provide recommendations to the Commission about firm transmission, has been overtaken by events. Energy Division staff is relieved of this responsibility.47

3.5.2. Section 399.16(b)(1)(B) Dynamic Transfer

A separate criterion for this portfolio content category is that the RPS-eligible generation facility providing the electricity "[h]as an agreement to dynamically transfer electricity to a California balancing authority." The term "dynamic transfer" refers to a range of methods by which a balancing authority receiving electricity generated in another balancing authority area may provide some or all of the functions and services typically provided by the balancing authority in which the generation facility is interconnected. (D.10-03-021 at 32-34.) As several parties point out, the actual dynamic transfer arrangement is made between the balancing authorities, not the generator and the buyer.48 The statutory direction should therefore be understood to mean the generation claimed for RPS compliance in accordance with this criterion is covered by an agreement that was executed by a California balancing authority, before the electricity is generated, to dynamically transfer electricity from the RPS-eligible generator outside a California balancing authority into the California balancing authority area during the time period in which the RPS-eligible electricity is generated. Because the techniques and protocols for dynamic transfer are evolving49, it is most reasonable to read this criterion broadly, as applying to those arrangements accepted by a California balancing authority as providing for dynamic transfer.

3.5.3. Characterization of "Unbundled Renewable
Energy Credits"

Parties sharply disagree about whether "unbundled renewable energy credits" originally associated with electricity that would meet the criteria of section 399.16(b)(1), are also included in this category.50

SB 2 (1X) does not define the term "unbundled renewable energy credits." It does, however, provide that "renewable energy credit" means:

... a certificate of proof associated with the generation of electricity from an eligible renewable energy resource, issued through the accounting system established by the Energy Commission pursuant to Section 399.25, that one unit of electricity was generated and delivered by an eligible renewable energy resource.51

This definition is unchanged from the original definition of a REC in SB 107, prior § 399.12(e)(1).

Throughout the history of the RPS program, a REC has been understood, consistent with its statutory definition (both previously and in SB 2 (1X)), as embodying the renewable and environmental attributes associated with the production of electricity from an eligible renewable energy resource.52 A REC records the production of RPS-eligible electricity, but "does not include any energy, capacity, reliability or other power attributes of the generation." (D.08-08-028 (Decision on Definition and Attributes of Renewable Energy Credits for Compliance with the California Renewables Portfolio Standard), OP 1.)

As CRS points out in its comments, the REC carries the renewable value and the RPS compliance value.53 Once a REC has been separated from the RPS-eligible energy with which it was originally associated, the underlying energy may not be counted for RPS compliance. 54

In the RPS program, the term "unbundled RECs" has consistently been understood to mean "RECs procured separately from the RPS-eligible generation originally associated with the RECs."55 This is the usage in other states and the industry in general.56 It is also the usage that the parties supported in their comments in response to the Ruling.57 It is not reasonable to believe that the Legislature would have intended to change the well-established meaning of this term without making explicit that it was doing so, either through a definition in new § 399.12, or through a description in a relevant substantive section. Therefore, the analysis of the place of unbundled RECs in the portfolio content categories is based on the established understanding of the term as denoting RECs that are separated from the electricity from which they were originally associated. In considering this issue, it is necessary to give meaning to every part of the statute, and to ensure that interpretation of each part is consistent with the statute as a whole. (Latkins v. Watkins Associated Industries (1993), 6 Cal.4th 644, 658-659.) Looking at the structure of § 399.16, it is clear that the portfolio content categories have fixed boundaries.58 Section 399.16(c) sets minimum and/or maximum percentages of RPS procurement from each portfolio content category for each compliance period. These required allocations are central to the purpose of the section, since they prescribe the actual percentages of procurement for RPS compliance. The language used is express and exclusive: "not less than;" 'not more than;" "not subject to the limitations of."59 These prescriptions for the use of procurement in each category for RPS compliance do not make sense, and could not be administered, unless there are bright lines separating the portfolio content categories.

Unbundled RECs, as TURN points out, are identified as belonging in § 399.16(b)(3) and are mentioned only in § 399.16(b)(3). The statutory text itself, unchanged from the introduction of SB 2 (1X) to its enactment, places unbundled RECs in that portfolio content category and in no other. When the Legislature "has employed a term or phrase in one place and excluded it in another, it should not be implied where excluded."60 Since the categories are express, prescriptive, and separate, § 399.16(b)(3) is where unbundled RECs belong.61 There is no reason, textual or otherwise, to believe that the Legislature specifically identified unbundled RECs as belonging in § 399.16(b)(3), but really intended some of them to be in § 399.16(b)(1).

In its comments on the PD, though not in its comments on the Ruling, IEP claims that a wording change in one of the six relevant versions of SB 722, the unsuccessful predecessor to SB 2 (1X), demonstrates that the Legislature intended to allow unbundled RECs to be classified in portfolio content categories other than § 399.16(b)(3).62 IEP asserts that a change in the syntax of proposed § 399.16(b)(3) 63 converted the Legislature's intent from classifying unbundled RECs exclusively in § 399.16(b)(3) to classifying unbundled RECs in §§ 399.16(b)(1) and (2), with only a residual group of unbundled RECs falling into § 399.16(b)(3).

This change in language is too slender a reed to bear the weight put on it by IEP. It is one of more than 20 changes to the language in proposed new § 399.16 that is made in the August 16, 2010 version of SB 722, and one of dozens of changes made to the language of SB 722 as a whole at that time. If the Legislature had intended to reverse completely the place of unbundled RECs in the portfolio content category scheme, it is reasonable to expect that some more direct and obvious method would have been chosen, such as expressly adding unbundled RECs to proposed § 399.16(b)(1). It is also reasonable to expect that such a significant change would be remarked upon in the legislative history since, as CUE points out, the treatment of unbundled RECs was one of the more significant issues in the development of the legislation, but IEP provides no evidence of legislative commentary on the point. Whatever the reason for the revision to the language, it is not reasonable to conclude that the revision was made in order to overthrow the prior understanding of the place of unbundled RECs in the statutory scheme.

Some parties64 urge that because generation meeting the criteria of § 399.16(b)(1) accomplishes some of the objectives of the statute, as set out in § 399.11, and is given a high RPS compliance value by § 399.16(c)(1), the unbundled RECs originally associated with electricity meeting the criteria for this category should also count in this category. This position is not supported by the plain meaning of § 399.16(b), discussed above. While this argument identifies a possible policy for RPS procurement, it is not the policy the Legislature chose when it enacted SB 2 (1X).

A more specific form of the argument for treating unbundled RECs as part of the § 399.16(b)(1) category is that unbundled RECs originally associated with RPS-eligible DG on the customer side of the meter have a high value in implementing RPS policy and providing for RPS compliance without additional investment in expensive transmission projects.65 This argument does not, however, take into account the Legislature's actions with respect to customer-side DG, most saliently Assembly Bill (AB) 920 (Huffman), Stats. 2009, ch. 376. This statutory revision to the net energy metering program makes clear that sales of surplus electricity from customer-side DG to the interconnected utility are sales of energy and RECs together. (§ 2827(h)(5)(A); D.11-06-016 (setting the net surplus compensation rate).) Thus, there is no question that such sales meet the criterion in § 399.16(b)(1) for generation with a first point of interconnection to the distribution system.

AB 920 also affirms the Commission's direction in D.05-05-011 and D.07-01-018 that the RECs originally associated with electricity from a DG system that is consumed on-site belong to the system owner. (§ 2827(h)(5)(A).) These RECs may be used to support the system owner's product claims (in accordance with the requirements of § 399.25 and CEC rules), but, if not used to support claims of the system owner, they may also be sold as unbundled RECs if all CEC requirements for RPS eligibility and WREGIS tracking are met.66

Thus, AB 920 specifically recognizes that the sale of RECs associated with the on-site use of electricity from an RPS-certified DG facility is different from the sale by the system owner of both energy and RECs to a retail seller. In considering the role of such unbundled RECs, it is also important to recognize that the on-site consumption of the electricity from the DG system has already produced an RPS benefit: it reduces the total retail sales of the interconnected utility, and thus reduces the amount of RPS-eligible procurement the utility requires. (See D.05-05-011 at 9.) Conferring an additional value on the unbundled RECs by considering them to meet the "first point of interconnection to distribution system" criterion is not warranted by any statutory language or Commission decision.67

3.5.4. Resale

In comments on PD, several parties sought clarification on whether, and under what circumstances, a retail seller could buy part or all of the procurement acquired through a contract for RPS procurement entered into by another entity and claim its purchased procurement for RPS compliance in the same portfolio content category as would have been used for the original procurement contract.68 As PG&E and TURN point out in their reply comments on the PD, nothing in the PD prevents such a resale from counting in the same portfolio content category, so long as certain conditions are met, to ensure that that the resale is not simply an elaborate transfer of unbundled RECs.

The conditions for allowing resale of part or all of a contract for RPS procurement to continue to meet the criteria of § 399.16(b)(1)(A) are:

· The original contract meets the criteria of § 399.16(b)(1)(A);

· The resale contract transfers only electricity and RECs that have not yet been generated prior to the effective date of the resale contract. 69

· The electricity transferred by the resale contract is transferred to the ultimate buyer in real time;

· For those transactions in which the RPS-eligible energy is scheduled from the eligible renewable energy resource that is not interconnected to a California balancing authority into a California balancing authority without substituting electricity from another source, the original hourly or subhourly schedule is maintained and the three other conditions above are met.

An additional condition is necessary for contracts with dynamic transfer (§ 399.16(b)(1)(B)). The resale must not be contrary to any condition imposed by any balancing authority participating in the dynamic transfer arrangement.

These requirements apply to all contracts for resale signed after the effective date of this decision.

3.5.5. Upfront Showing and Compliance Determination

The upfront showing required of IOUs in their advice letters for procurement projected to meet either of the two criteria based on the generator's point of interconnection would be straightforwardly based on showing that the RPS-eligible generator has the applicable first point of interconnection. The compliance determination would similarly require a demonstration that the generator meets the interconnection requirement.

The third criterion in this group, scheduling electricity into California without substitute electricity, is significantly more complex. Unlike firmed and shaped procurement, discussed below, transactions, in which the electricity is scheduled to a California balancing authority without substitution require a transmission path from the renewable generating facility to the California balancing authority in real time. While several parties (e.g., LADWP, NextEra, PG&E, and SDG&E) suggest that the combined use of WREGIS and e-Tags can document that this criterion has been met, this may not in fact be possible at this time.70 First, WREGIS uploads renewable facility generation data on a monthly basis,71 but the parties agree that the schedule for this criterion is no longer than hourly. Some parties propose that monthly aggregation nevertheless should be used as the basis for this criterion.72 Others argue that monthly aggregation would result in overstating the quantity of generation meeting this criterion, because, as TransWest explains, "it would not be possible to ensure that only the renewable energy scheduled for that hour and produced in that same hour would be credited." (Reply comments at 2-3).

Further, it is unclear whether e-Tags can currently be used to demonstrate that specific RPS-eligible generation was delivered to a particular California balancing authority. Although enXco and Iberdrola state that e-Tags often carry information identifying the generator, PacifiCorp points out that it is not required that the generator's balancing authority provide such generator-specific information on the e-Tag. (PacifiCorp Reply comments at 4.) It is clear, at the least, that information on e-Tags will become increasingly in demand as transactions with RPS-generation outside a California balancing authority scheduled into a California balancing authority become increasingly complex and sophisticated. This can be seen in the recent improvement to WREGIS functionality to match e-Tags and WREGIS Certificates (i.e., RECs tracked in WREGIS.

We therefore agree with SCE that ". . . the reality is that there is currently no system that, in the near term, can gather all of the data necessary to operationalize and document the product categorization language" for this criterion. (SCE comments at 5.) Parties suggest several solutions to this real problem. PG&E and SDG&E propose that, since monthly aggregation is what is available through WREGIS, that is what should be used to determine compliance with this category. UCS asserts that the hourly determination must be made, whether or not there is an "automated" way to do so. SCE suggests that each retail seller retain information from WREGIS, e-Tags, transmission schedules, and generation facility metering data in an "auditable" form, presumably available to Energy Division staff, so that staff could go through the vast amount of data from disparate sources that SCE states would be necessary.

PG&E's suggestion is not viable. The statutory criterion is maintenance of an hourly schedule. It is not consistent with the statute nor with this Commission's responsibilities under the RPS program to substitute a time period more than 700 times longer than the statutory criterion when determining compliance with this portfolio content category.

SCE's proposal that the retail seller retain all records so that scarce Commission personnel can make the compliance determination is not consistent with the principle that the retail seller is responsible for complying with RPS requirements. Putting forward "auditable" records as the basis for compliance determinations when it is extraordinarily unlikely that actual auditing will be possible, is essentially giving up on determining compliance.

The current functionalities of WREGIS and e-Tags were not designed with SB 2(1X) in mind, and cannot provide all the information necessary for the Commission to determine with a high level of confidence that RPS procurement could or did meet the statutory requirements of section 399.(b)(1)(A). Therefore, in this decision the Commission provides guidance for the upfront showing of portfolio content classification of IOUs' planned procurement and for the administration of the compliance determination of portfolio content category classification. It is apparent, however, that effective and efficient administration of the portfolio content mandates of SB 2 (1X) will require modifying existing systems or developing new ones.

In the interim, SCE's proposal should be used to develop a method for retail sellers to demonstrate to the Commission that they have and can provide information that would show compliance with the criterion of scheduling into a California balancing authority without substituting electricity. The burden of demonstrating compliance (or likelihood of compliance) with the disparate criteria for this portfolio content category may be large. Retail sellers must be prepared to carry that burden both in IOUs' upfront showings for contract approval and in providing documentation for compliance determinations.

For approval of contracts meeting the criteria of section 399.16(b)(1)(A), IOUs must make an upfront showing that includes at least:

· The RPS-eligible generator has its first point of interconnection with the WECC transmission system within the boundaries of a California balancing authority; or

· The RPS-eligible generator has its first point of interconnection with the distribution system within the boundaries of a California balancing authority; or

· If the criterion of hourly scheduling into a California balancing authority without substitution of electricity is being used, that an hourly schedule can be maintained and substitution of electricity from another source is unlikely to occur, whether because the transmission arrangements are sufficiently reliable or for some other documented reason.

Compliance determinations are similar for all retail sellers, requiring documentation that the criteria for this category were met. Any retail seller claiming generation in this category must be prepared to show, in a Commission RPS compliance filing, that:

_ how much RPS-eligible energy was generated;

_ how much generation was scheduled;

_ how much generation was delivered;

_ how much of the scheduled delivery was provided by ancillary services; and

_ that none of the energy scheduled into the California balancing authority was substitute energy.

Such a demonstration is required in addition to the reports retail sellers provide to the CEC for verification of the generation. Energy Division staff may also require the retail seller to analyze all relevant information for a sample of the hours claimed in this category.

If dynamic transfer is being used, an IOU's upfront showing must provide appropriate documentation of the dynamic transfer agreement, that the generation is included within the scope of the agreement, and that the agreement will be in operation at the time of the generation covered under the contract. At the stage of compliance determination, all retail sellers claiming generation under this criterion must be able to demonstrate that the dynamic transfer mechanism was in place and effective at the time of the generation claimed, and that the generation was actually dynamically transferred. Such a demonstration is required in addition to the report that retail sellers provide to the CEC for verification of generation.

The Director of Energy Division is authorized to develop a methodology for both the upfront showing and the compliance determination, for all procurement claimed to meet any of the criteria of § 399.16(b)(1). This methodology may include the elements discussed above, as well additional elements that may be determined to be relevant, including element necessary to incorporate information about changes in dynamic transfer methods. Energy Division staff are further authorized to consult with the parties, CEC staff, and WREGIS staff to develop a more comprehensive and long-term approach to the elements necessary for IOUs' upfront showings and compliance determinations for all retail sellers claiming RPS procurement that meets the criteria of § 399.16(b)(1).

3.5.6. Pipeline Biomethane

TURN and Clean Energy disagree about whether generation using pipeline biomethane as fuel would meet the criteria in section 399.16(b)(1). TURN argues that generation from an RPS-eligible generation facility that uses pipeline biomethane (i.e., methane made from renewable sources and transported in the gas pipeline system) as part of its fuel should not count in this category, even if the generation facility is directly interconnected within a California balancing authority area. TURN argues that such generation merely reproduces the pollution and greenhouse gas emissions of natural gas-fueled generation. Clean Energy, on the contrary, asserts that such generation meets all the requirements for RPS eligibility and of this category.

It is not necessary to attempt to resolve this dispute now. For purposes of classifying RPS procurement into the appropriate portfolio content category, the CEC's determination of RPS eligibility is the definitive first step. In the Draft Eligibility Guidebook (at 24), CEC staff indicates that the criteria for determining the RPS eligibility of pipeline biomethane are under review. It is premature for this Commission to address the place of generation using pipeline biomethane as a fuel source in the new portfolio content categories while the CEC is considering changes to the eligibility criteria for pipeline biomethane.

3.6. Section 399.16(b)(2) Firmed and Shaped Transactions Providing Incremental Energy

This section of the statute is more complex than its relatively simple expression suggests. Firming and shaping provides flexibility in managing and delivering RPS procurement from generation facilities not located in California balancing authority areas. This flexibility, however, makes it more difficult to characterize firming and shaping transactions in a way that can be applied uniformly and reliably across a range of possible transactions. The two key terms used in this category, "firmed and shaped," and "incremental," are not defined in SB 2 (1X). The best method for characterizing transactions in this category is therefore practical, rather than abstract, drawing on the range of suggestions made by the parties.

3.6.1. Firmed and Shaped

As PG&E notes, the term "firmed and shaped" does not have a generally accepted definition within the industry. Many different commercial arrangements can be described using this term.73 In the REC White Paper, Commission staff provided descriptions of firming and shaping.74 In the fourth edition of its Eligibility Guidebook, the CEC described several possible configurations of firming and shaping transactions.75

SCE proposes that the REC White Paper be used as the basis for interpreting the "firmed and shaped" portfolio content category. Several parties assert that the CEC's description in the 4th edition of its Eligibility Guidebook should be adopted as the meaning of "firmed and shaped" in SB 2 (1X).76

While they are each instructive, neither of these prior efforts fully serves the purpose of implementing this new portfolio content category. The REC White Paper discussion is at a high level of generality that necessarily does not take account of the developments in the renewable energy industry in the past five years. The CEC's description of firmed and shaped transactions emerged to address the "delivery" element of RPS eligibility under the law prior to SB 2 (1X). It was not, and could not have been, intended to describe a portfolio content category of new § 399.16.77

Parties have both described firmed and shaped transactions and made proposals for interpreting the statutory requirements. Parties agree that this category applies to RPS-eligible generation located outside the boundaries of a California balancing authority area. There is also broad agreement, reflected in the Reference Proposal, that the scheduling of substitute electricity in a firmed and shaped transaction should occur after the RPS-eligible generation, on a schedule greater than hourly but within a calendar year of the RPS-eligible generation.

SB 2 (1X) provides both more precise requirements in new § 399.16(b) and stricter usage limitations in new § 399.16(c) than those used in the implementation of SB 107. It is reasonable to interpret this more prescriptive statutory scope as narrowing the range of transactions that would meet the criteria of § 399.16(b)(2).

In order to meet the requirements of the statute in a way that is both reasonably transparent and commercially reasonable, firmed and shaped transactions should be seen as fundamentally providing substitute energy in the same quantity as the contracted-for RPS-eligible generation, in order to fulfill the scheduling into a California balancing authority of the RPS-eligible generation, which can be set in a manner that meets the timing and quantity requirements of the retail seller. As a practical matter, the original RPS-eligible generation is consumed elsewhere, typically but not necessarily close to the generator.

TURN makes the additional proposal that any substitute electricity must be provided by generation from the same WECC subregion as the RPS-eligible generator. This proposal seeks to control the complexity of firmed and shaped transactions, as well as to incorporate an intuitively appealing proximity between the source of the RPS-eligible generation and the source of the substitute energy. While this proposal is interesting, its implications are not clear enough at this stage of this proceeding for the Commission to adopt it.78

In order to provide effective guidance to RPS market participants and to Commission staff evaluating RPS procurement, the general characteristics of a firmed and shaped transaction must be translated into specific and practical elements. The following elements maintain the flexibility inherent in the firmed and shaped category, while providing sufficient particularity to allow transactions in this category to make a meaningful contribution to RPS compliance.79 The elements are:

1. the buyer's simultaneous purchase of energy and associated RECs from the RPS-eligible generation facility without selling the energy back to the generator;80

2. the availability of the purchased energy to the buyer (i.e., the purchased energy must not in practice be already committed to another party); and

3. the initial contract for substitute energy is acquired no earlier than the time the RPS-eligible energy is purchased and no later than prior to the initial date of generation of the RPS-eligible energy under the terms of the contract between the buyer and the RPS-eligible generator.81

In order to count in this category, a firmed and shaped transaction must also provide "incremental electricity" that is "scheduled into a California balancing authority area."

3.6.2. Incremental

Parties suggest several possible readings of the "incremental" requirement. PG&E, SCE, and SDG&E propose that "incremental" should be interpreted to mean "procured at any time after June 1, 2010." This argument is based on §§ 399.16(c) and (d), which accord different portfolio content treatment to contracts signed before or after that date.82 Several parties, including AReM, CEERT, CMUA, IEP, and UCS propose that "incremental" should be interpreted to mean "not in the portfolio of the retail seller prior to the firmed and shaped transaction."

The utilities provide no justification for reading §§ 399.16(c) and (d) into § 399.16(b) (2), and none is apparent. The June 1, 2010 date is expressly tied to the limitations on the use of procurement in each portfolio content category for RPS compliance. If the same date were intended to provide the meaning of "incremental," it is logical to think that it would be included in § 399.16(b)(2), or at least cross-referenced. The absence of any textual connection between the phrase "incremental electricity" and the June 1, 2010 date renders the utilities' proposed reading unconvincing.

Several parties argue that firmed and shaped deals can meet the criteria of this category by "tagging" RECs to any substitute energy identified by the retail seller.83 This view is in part a hold-over from the procurement practices sanctioned by the CEC's interpretation of the "delivery" requirement under SB 107. (See Eligibility Guidebook, 4th edition, at 32-34.) The practice of "tagging" is incompatible with both the requirement that electricity be acquired to substitute for the RPS-eligible generation and the requirement that "incremental electricity" be scheduled into a California balancing authority. Accordingly, the "tagging" approach can not be carried forward into the administration of § 399.16(b)(2).

The proposal to interpret "incremental" in a way closer to its ordinary meaning is more persuasive. The interpretation does not need to be as formal as NextEra's "but for" causal approach. Instead, the straightforward interpretation proposed by several parties that "incremental" as "not in the portfolio of the retail seller claiming the transaction for RPS compliance prior to the firmed and shaped transaction" is adopted.

3.6.3. Ratepayer protection requirements

The fundamental elements of firming and shaping and "incremental" energy set forth above apply to all transactions that any retail seller seeks to include as meeting the criteria of § 399.16(b)(2) for RPS compliance. In order to protect the interests of ratepayers, IOUs must also meet additional requirements designed to allow evaluation of the price reasonableness of their firmed and shaped contracts, to provide a basis for the cost containment measures the Commission will develop84, and to aid in resource planning.

DRA, Sierra Club California, TURN, and UCS assert that ratepayers will not benefit from firmed and shaped transactions unless those transactions provide relatively long-term price stability, as compared to the potential volatility of fossil fuel market prices. DRA, TURN, and UCS propose two elements to address this concern:

· contracts for substitute energy must be at least five years long;

· contracts for substitute energy must be at a fixed price, not indexed to fossil fuel-generation market prices.

SCE points out that these requirements are too detailed and too significant to be read into the statutory requirements for firmed and shaped transactions of all retail sellers. However, in exercising its responsibility to protect ratepayers from unreasonable costs, the Commission may consider imposing additional requirements on IOUs' contracts.

In this context, the suggestion of DRA, TURN, and UCS that the initial contract for substitute energy be at least five years in duration may be considered. Parties generally agree that a contract for substitute energy would not often be available for the entire duration of a long-term RPS procurement contract, but it is reasonable to believe that substitute energy contracts for up to five years may be readily obtained.85 Contracts for substitute energy of this length will help ensure that the firmed and shaped transaction is sufficiently well-defined that Energy Division staff can reasonably evaluate the viability and cost of the deal when it is presented to the Commission for approval via advice letter.

Thus, the proposal that the contract for substitute energy must be at least five years in duration is adopted for IOUs, with one common-sense modification proposed in comments on the PD.86 The contract for substitute energy must either be at least five years in duration, or as long as the contract for RPS-eligible energy, whichever is shorter.87 If the duration of the contract for substitute energy is shorter than that of the contract for RPS-eligible energy, the IOU must provide subsequent contracts for substitute energy (that is incremental, as defined in this decision) to the Commission a reasonable time in advance of the initial date of generation of the substitute energy under the contract.88 The IOU should submit the original substitute energy contract with the contract for RPS procurement, and should submit any subsequent contracts for substitute energy via a Tier 2 advice letter.

DRA, TURN, and UCS make the additional proposal that substitute energy contracts must be at a fixed price. They argue that this requirement would carry forward the value of fixed-price long-term contracts for RPS-eligible electricity in hedging against the volatility of fossil fuel prices. The large IOUs object to this proposal. All three large IOUs argue that they meet the goals of price stability by submitting hedging plans for their entire portfolios to the Commission. Thus, PG&E asserts, enforcing price stability at the level of individual firmed and shaped RPS contracts is unnecessary and inefficient.

Although the concern about hedging value is a valid one, it should not be enforced through requiring fixed-price substitute electricity in firmed and shaped contracts at this time. SB 2 (1X) eliminates the prior RPS cost containment regime that included, among other things, a statutory yardstick for the prices of individual contracts (the market price referent), and instructs the Commission to develop a new cost containment mechanism.89 The new cost containment method, when implemented, should guide the determination of whether to require fixed-price contracts for substitute electricity in firmed and shaped transactions.

3.6.4. Resale

As discussed in section 3.5.4. above, it is possible for a retail seller to buy all or a portion of a contract entered into by another entity and apply the contract and the procurement acquired through it to the retail seller's RPS compliance in the same portfolio content category as the original contract would have been classified, if certain conditions are met. The conditions for allowing resale of part or all of a contract for RPS procurement to continue to meet the criteria of § 399.16(b)(2) are:

· The original contract meets the criteria of § 399.16(b)(2);

· The resale contract transfers only electricity and RECs that have not yet been generated prior to the effective date90 of the resale contract;

· The resale contract transfers the original arrangement for substitute electricity (e.g., source and quantity);

· The resale contract retains the scheduling of the substitute electricity into a California balancing authority as set out in the original firming and shaping transaction; and

· The transaction continues to provide incremental electricity scheduled into a California balancing authority.

3.6.5. Upfront Showing and Compliance Determination for Section 399.16(b)(2)

IOUs seeking Commission approval of contracts in this category must supply sufficient information for Energy Division staff to review the proposed contract and make a reasoned evaluation of the terms of the contract, the value to ratepayers, and the projected cost over the life of the contract. This includes, at the least, both the contract for RPS-eligible electricity and the initial contract for substitute electricity, as well as evidence demonstrating that the transaction provides incremental electricity. If, as Iberdrola states is possible in its comments on the PD, the firming and shaping arrangements are to be carried out by the RPS-eligible generator, or an affiliate of the generator, the IOU's upfront showing must include information from which Energy Division staff can determine that any energy to be sold back to the generator or its affiliate is for the purpose of firming and shaping. The Director of Energy Division is authorized to require IOUs to submit any additional information relevant to evaluating procurement contracts involving firmed and shaped transactions that are presented to the Commission for approval via advice letter.

Any retail seller seeking to count RPS procurement in this category for RPS compliance must provide information to Energy Division staff from which staff can determine compliance with the criteria for this category. Staff must be able to determine that the elements of a firmed and shaped transaction described in this decision are present in the procurement at issue, including the requirement that the substitute energy scheduled into a California balancing authority is "incremental" as defined in this decision, or subsequent Commission decisions or legislative enactments. The Director of Energy Division is authorized to require retail sellers to submit any information relevant to making compliance determinations for the "firmed and shaped" portfolio content category.91

3.7. Section 399.16(b)(3) Unbundled RECs and Electricity that does not Qualify Under Sections 399.16(b)(1) or (2)

This portfolio content category contains three elements:

The first two elements of this category are difficult to characterize. If an RPS procurement transaction does not qualify under paragraph (1) or (2), that means that the transaction does not include electricity that is:

· from an RPS-eligible generation facility that has its first point of interconnection with a California balancing authority;

· scheduled from an RPS-eligible generation facility into a California balancing authority without substituting electricity from another source;

· dynamically transferred to a California balancing authority; or

· firmed and shaped, providing incremental electricity scheduled into a California balancing authority.

The most natural reading of this strongly negative criterion (i.e., "does not qualify") is that it is intended to cover a quantity of RPS-eligible generation that was intended to meet a particular criterion, but for some reason, did not do so. One example might be a firmed and shaped transaction, where some of the substitute electricity is not scheduled in the calendar year of the RPS-eligible generation. "Any fraction of the electricity generated" may be understood to apply, for example, to electricity that is scheduled into a California balancing authority without substituting electricity from another source, but is generated in excess of the schedule.

Unbundled renewable energy credits, defined and discussed in section 3.5.3. above, are likely to be the largest component of this category. Because in D.10-03-021, as modified by D.11-01-025, the Commission set rules for the use of unbundled RECs, it is appropriate to make an initial transition of the existing rules on unbundled RECs to the new portfolio content category requirements. The Commission will further consider the prior rules, and may reexamine the rules identified here, as well as other rules, in later decisions that continue the implementation of SB 2 (1X).

3.7.1. Rules for unbundled RECs

As explained in D.10-03-021, RECs can be unbundled from the RPS-eligible generation with which they were originally associated and sold separately. In that case the transaction is a transaction for unbundled RECs. This is the case both in the framework of D.10-03-021 and the framework of new § 399.16. Regardless of whether the original generation and RECs would have counted in the "bundled" category under D.10-03-021, or in another portfolio content category under new § 399.16 if the RECs had been retired for RPS compliance without being transferred, once they are unbundled and transferred, the RECs are by definition unbundled RECs, subject to the rules of that portfolio content category.

In addition, some rules for the use of unbundled RECs set forth in D.10-03-021, as modified by D.11-01-025, are not affected by new § 399.16 and continue in force. These include:

1. The temporary price cap of $50.00/REC, which will expire December 31, 2013. (D.10-03-021, OP 19.)

2. The prohibition on unbundling RECs from the first three years of a contract that is for unbundled RECs only if that contract has been earmarked to apply to a shortfall in a retail seller's annual procurement target. (OP 16.)

3. The prohibition on unbundling RECs from the first three years of a contract that is not for unbundled RECs only if that contract has been earmarked to apply to a shortfall in a retail seller's annual procurement target. (OP 14.)

Further, the new portfolio content categories do not disturb the overarching tenet that once RECs have been unbundled and sold separately from the RPS-eligible electricity with which they were originally associated, the electricity may not be used for RPS compliance. (OP 12, 13; new § 399.25(b), (c).)

3.7.2. Upfront Showing and Compliance Determination for Section 399.16(b)(3)

In making an upfront showing in an advice letter seeking approval of a contract for unbundled RECs, an IOU must show, for contracts signed prior to December 31, 2013, that the levelized price does not exceed $50/REC.92 The IOU must also provide sufficient information for the Commission to determine that the RECs sought to be purchased were originally associated with RPS-eligible generation.

Because it is difficult to predict in advance all the characteristics of other RPS procurement that would fit within § 399.16(b)(3), an IOU's upfront showing for approval of such procurement contracts, if any, must be sufficient for the Commission to determine that the electricity was generated by an RPS-eligible facility. The upfront showing must also describe the procurement with enough particularity that the Commission can determine that it is likely not to meet the criteria of either § 399.16(b)(1) or § 399.16(b)(2).

Finally, an IOU subject to the minimum and maximum requirements for procurement counting in particular portfolio content categories set forth in § 399.16(c) must provide sufficient information for the Commission to determine that it is reasonably likely that the proposed procurement will fall within the quantitative requirements.

For compliance determinations for unbundled REC purchases, all retail sellers must provide information allowing the Commission to determine that the unbundled RECs claimed for RPS compliance were retired in WREGIS for RPS compliance as required by new § 399.21(a)(6). For compliance determinations for procurement meeting either of the other criteria in new § 399.16(b)(3), the retail seller must provide enough detail about the transactions so that the portfolio content category classification may be properly determined and demonstrated to the satisfaction of the Director of Energy Division.

3.7.3. Exceptional Department of Water Resources (DWR) contracts

There is one very limited exception to the classification of unbundled RECs. During the energy crisis, pursuant to authority granted by Water Code § 80000 et seq., DWR entered into a number of long-term contracts for customers of California's utilities. In A.00-11-038, this Commission subsequently distributed the DWR contracts to be administered by the three large utilities, with the utilities' customers receiving the energy from the contracts.

In three of its contracts, DWR procured energy from RPS-eligible wind farms in California, but expressly did not also buy the RECs associated with that energy. Two of the contracts (with Cabazon Wind Partners LLC and Whitewater Hill Wind Partners LLC) are assigned to SDG&E. One, with Mountain View Power Partners, is assigned to SCE. The customers of both SDG&E and SCE are receiving electricity generated by California RPS-eligible wind facilities, but because the contracts did not also convey the RECs, the utilities (and thus their ratepayers) are not receiving credit toward RPS compliance.

Both SDG&E and SCE have sought to buy RECs from these facilities and "reunite" the RECs with the underlying generation that their customers receive from the DWR contracts.93 As discussed above, once the electricity and the RECs are separated, the RECs are "unbundled" and the underlying electricity may not be used for RPS compliance. It is generally not possible to reattach RECs that have been unbundled from the energy with which they are originally associated.

In this unique and limited circumstance, however, SDG&E and SCE should be allowed to acquire the RECs separately from the energy but receive RPS compliance credit as though they had been purchased together. Neither the utilities nor their ratepayers had any part in DWR's decision to buy only the electricity and not the RECs; neither the utilities nor their ratepayers should be disadvantaged by the assignment to them of these DWR contracts. SCE and SDG&E should be able to obtain the RECs that would have been part of the contracts if the energy and RECs had been procured together, thus making the generation under the DWR contracts RPS-eligible.

We note two elements that confine this determination within narrow boundaries. First, there are no other DWR contracts from the energy crisis that are like these three, so this circumstance will never recur. Second, making this one-time exception will have no lasting impact on the administration of § 399.16 because these DWR contracts have little or no time left to run.94

3.8. Section 399.16(c) Usage Limitations

This section sets out the practical application of the portfolio content categories. It provides limitations on using RPS procurement in each of the three portfolio content categories for each compliance period. For the first portfolio content category, the statute sets minimum procurement percentages. For section 399.16(b)(3), its sets maximum percentages. Section 399.16(b)(2) is treated as residual. Numerically, these requirements are straightforward. They apply beginning with the first compliance period under SB 2 (1X), 2011-2013. This decision addresses the application of the minimum and maximum requirements to only "the eligible renewable energy resource electricity products associated with contracts executed after June 1, 2010." This provision must also be read in conjunction with § 399.16(d).

The Director of Energy Division is authorized to make any changes necessary to reporting formats in order to provide for accurate and accessible reporting by retail sellers of contracts subject to the usage limitations on the new portfolio content categories. This subject may be revisited in later decisions implementing SB 2 (1X).

3.9. Section 399.16(d) Contracts or Ownership Agreements Prior to June 1, 2010

This section sets a special rule for "[a]ny contract or ownership agreement originally executed prior to June 1, 2010."95 It is reasonable to read this phrasing as applying to any RPS procurement transaction that was signed prior to June 1, 2010, as long as it meets the three additional criteria set out in the statute.96

PG&E and SCE point out that not only contracts but "ownership agreements" are covered by this section. PG&E asserts, without opposition, that the meaning of an "executed ownership agreement" should include an agreement between a retail seller and a third party to acquire or develop an RPS-eligible generation resources. Often, this will be in the form of a contract for the third party to engineer, procure, and construct the generation facility (usually referred to an "EPC contract"). PG&E's reading reasonably sets the EPC contract on equivalent footing with a power purchase agreement signed by an IOU with an RPS-eligible generation facility, and is adopted.

SCE's comments focus on IOU ownership of the generation facility. SCE asserts, also without opposition, that UOG is included in the arrangements covered by § 399.16(d). In its comments on the PD (at 13-14), SCE that UOG "built" prior to June 1, 2010 be considered covered by § 399.16(d). While SCE's idea is sound, "built" is too imprecise to use as a demarcation point for the very different requirements attaching to RPS procurement pursuant to pre-June 1 and post-June 1, 2010 procurement arrangements. A more precise and readily ascertainable standard is that UOG having a commercial online date prior to June 1, 2010 is covered by § 399.16(d).

The direction that such transactions "shall count in full towards the procurement requirements established pursuant to this article. . ." is the subject of some controversy. Many parties argue that it means that no restrictions or conditions on procurement set by SB 2 (1X) apply to such contracts.97 Others, including DRA, LSA, TURN, and UCS, insist that some restrictions do apply to these contracts.

AReM argues that the reach of this section should be extended, at least for ESPs, to cover contracts signed in the same time period as allowed by D.11-01-026 (i.e., contracts signed prior to January 13, 2011). AReM asserts that the Commission's prior decision should be honored in the transition to the SB 2 (1X) regime, because ESPs relied on it in organizing their RPS compliance. SCE and TURN argue that the statutory provisions must apply equally to all retail sellers.

AReM's position must be rejected. The Legislature has the power, though it does not often exercise it, to enact a civil (not criminal) law that will reach and change the legal effect of actions taken in the past. In re Marriage of Bouquet, 16 Cal.3d 583, 586-88 (1976). The Legislature's direction in SB 2 (1X) is clear that only contracts signed prior to June 1, 2010 may be given the special "count in full" treatment. This is express in § 399.16(d) itself. In § 399.16(c), the Legislature provides that the new portfolio content categories (and thus the accompanying limitations on their use) apply to contracts signed after June 1, 2010. This determination is within the authority of the Legislature, and there is no ambiguity in these directions that would require interpretation or harmonization with D.11-01-026.

We recognize that there may be complex issues of interpretation with respect to other implications of new § 399.16(d), for example, the limitations on applying excess procurement from one compliance period to a subsequent compliance period (new § 399.13(a)(4)(B).). We leave these questions to subsequent decisions on compliance and procurement more generally. For the sake of clarity and simplicity, in this decision we address the significance of § 399.16(d) in the context of the portfolio content requirements of § 399.16.

The parties' consensus reads the "count in full" instruction to mean that the limitations on the use of procurement in each of the three portfolio content categories do not apply to procurement from contracts signed prior to June 1, 2010, as long as the three qualifying conditions are met. While this is generally an accurate reading of the statute, one caveat must be supplied. The general exemption from the usage limitations in new § 399.16(c) applies only to RECs retired for RPS compliance from the originally contracted procurement. If any RECs from a contract signed prior to June 1, 2010, are unbundled and sold separately after June 1, 2010, the underlying energy may not be used for RPS compliance; and the unbundled RECs will be counted in accordance with the limitations on § 399.16(b)(3), as set out in § 399.16(c)(2). This follows from the statutory language, which applies only to a "contract or ownership agreement originally executed prior to June 1, 2010." (Emphasis added.) A contract signed after that date, even if conveys RECs originally part of a contract signed prior to June 1, 2010, is not covered by § 399.16(d).

3.10. Section 399.16(e)

This section provides an option for a retail seller to ask the Commission to relieve it of some of the requirements of new § 399.16(c). This section is more appropriately considered with other issues of RPS compliance, and will not be addressed in this decision.

3.11. Application of § 399.16 to Small and
Multi-Jurisdictional Utilities

Pursuant to new §§ 399.18(b)98 and 399.17(b),99 small and multi-jurisdictional utilities (SMJUs) meeting the criteria set out in those sections are not subject to the requirements and limitations the use of procurement in each portfolio content category. This decision affirms the Scoping Memo's uncontested ruling on that point. (Scoping Memo, Ruling Paragraph 8.)

This exemption does not, however, affect the portfolio content category itself of SMJUs' RPS procurement transactions. Thus, if a small utility buys unbundled RECs, those unbundled RECs are subject to the rules for that portfolio content category; but when the small utility retires those RECs for RPS compliance, it may use them without regard to the limitations in § 399.16(c)(2).

3.12. Next Steps

This decision sets the parameters for procurement by retail sellers to meet the requirements of the portfolio content categories established by SB 2 (1X). It provides guidance to IOUs seeking Commission approval of RPS procurement contracts and outlines the obligations of all retail sellers in providing information to Commission staff for compliance determinations.

The implementation of new § 399.16 will nevertheless require, as noted throughout this decision, work by Energy Division staff, in consultation with the parties and with collaborative staff at the CEC, to revise and update this Commission's processes for reviewing and approving utility advice letters for RPS procurement and for prescribing, reviewing, and evaluating documentation of RPS procurement compliance by all retail sellers. The Director of Energy Division is encouraged to set priorities for this effort promptly, and to begin the work as soon as practicable.100 The Commission will also address important issues about compliance and enforcement under the new SB 2(1X) rules, as well as about the "seams" between the old and new RPS regimes that have been raised in party comments, in subsequent decisions.

6 The RPS program was initiated by SB 1078 (Sher), Stats. 2002, ch. 516, which set a goal for retail sellers of providing 20 per cent of their retail sales from eligible renewable energy resources by 2017. SB 107 (Simitian), Stats. 2006, ch. 464, accelerated the 20% goal to 2010, as well as making other changes in the RPS program. See also the OIR for this proceeding, at 1, 7.

7 SB 2 (1X) is substantially similar to SB 722 (Simitian), introduced in the 2009-2010 session of the Legislature but not enacted.

8 Gov't Code § 9600(a).

9 The Commission has jurisdiction, for RPS purposes, over the first three groups of retail sellers; it does not have jurisdiction over publicly owned utilities. Pub. Util. Code §§ 399.12(j); 399.30(p).

10 Many parties have adopted the term "bucket" to refer to a portfolio content category; thus, "Bucket 1," "Bucket 2," and "Bucket 3." While this shorthand can be useful, the analysis presented in the parties' comments and carried through in this decision reveals that the portfolio content categories have a more complex structure than can be captured by the "bucket" metaphor. This decision therefore does not use the "bucket" designation.

11 Imperial Merchant Services, Inc. v. Hunt (2009) 47 Cal. 4th 381, 387-388. See also, e.g., People v. Canty (2004) 32 Cal.4th 1266, 1276; Lungren v. Deukmejian (1988) 45 Cal.3d 727, 735.

12 In the RPS program to date, retail sellers submit semi-annual compliance reports, but their final compliance reports for a compliance year are not required until the California Energy Commission (CEC) has completed its verification process for that year. D.06-10-050. New § 399.15 makes significant changes to the compliance periods and targets for retail sellers. The Commission will address the process of adjusting compliance reporting requirements to the new statutory scheme, including the new portfolio content categories, in later decisions implementing SB 2 (1X). At this time, the CEC has not indicated how it will include the new provisions in its verification process.

13 See generally, comments of Iberdrola and Powerex on the Ruling. Many parties commented on sources of information related to procurement classification in the new portfolio content categories; this list is not intended to be exhaustive.

14 WREGIS creates a Certificate for each MWh of RPS eligible generation.

15 See WREGIS Change Request Form, found at

http://www.wregis.org/uploads/files/931/WREGIS%20Change%20Control%20Form%20PCR165.pdf.Z

16 The Commission generally does not review the contracts of multi-jurisdictional utilities. See Decision 08-05-029; see also § 399.17, discussed below.

17 Parties assume that the highest value will be realized with respect to procurement meeting the requirements of § 399.16(b)(1); the next, procurement meeting the requirements of § 399.16(b)(2); and the lowest value, as a rule, to procurement meeting the requirements of § 399.16(b)(3). See, e.g., comments of CMUA and NV Energy.

18 The actual determination that procurement meets the requirements of a particular portfolio content category will be made by Commission staff retrospectively, on the basis of compliance information submitted by each retail seller, as discussed below.

19 The assertion by some parties (e.g., AReM and PG&E) that the CEC should make portfolio content category compliance determinations confuses this Commission's authority over retail sellers' compliance with RPS procurement rules pursuant to §§ 399.13, 399.15, and 399.16 with the CEC's authority over certification of eligible renewable energy resources and verification of claimed generation pursuant to § 399.25.

20 As a general matter, ESPs and CCAs must provide relevant compliance documentation to Energy Division staff. (D.06-10-019, D.06-10-050, D.11-01-026.)

21 In order to reduce confusion in the transition between prior rules and SB 2 (1X), the rules for retirement of renewable energy credits (RECs) should be briefly addressed. D.10-03-021 requires that all RECs (associated with energy from any type of transaction) must be retired in WREGIS for RPS compliance within three compliance years from the date of the generation with which the RECs are associated, including the year in which the generation occurred. (OP 10.) SB 2 (1X), on the other hand, permits all RECs to remain in an active account in WREGIS for up to 36 months prior to retirement for RPS compliance. (§ 399.21(a)(6).)

To mesh the two retirement requirements without creating a gap between the years prior to January 1, 2011 (when RPS compliance was annual) and after January 1, 2011 (when the new compliance periods begin), it is reasonable to apply the "within three compliance years" regime of D.10-03-021 to allow RECs associated with generation from 2008, 2009, or 2010 to be retired for compliance year 2010, or any earlier compliance year, in accordance with the rules governing compliance for all RPS compliance years prior to 2011. That is, the WREGIS Certificates (i.e., RECs) may be retired for the 2010 compliance year, consistent with the CEC's directions for submitting reports with generation data for a given compliance year. This allows orderly completion of compliance for all years in which an annual procurement requirement, rather than the new compliance periods set by SB 2 (1X), was in effect. It is also consistent with the reasonable commercial expectations of parties after the issuance of D.10-03-021.

22 These requirements are found in the Public Resources Code, in current Pub. Res. Code § 25471(a) and current Pub. Res. Code § 25741(b)(2).

23 New Pub. Util. Code § 399.21, added by SB 2 (1X), amends and renumbers current § 399.16, which authorizes the use of renewable energy credits (RECs) for RPS compliance under certain conditions. New § 399.21 makes a conforming change to eliminate the requirement in current § 399.16(a)(3) that the electricity associated with a REC must be "delivered to a retail seller, the Independent System Operator, or a local publicly owned electric utility."

24 The current edition of the Eligibility Guidebook is the fourth edition (January 2011), found at http://www.energy.ca.gov/2010publications/CEC-300-2010-007/CEC-300-2010-007-CMF.PDF. Pursuant to Rule 13.9 of the Commission's Rules of Practice and Procedure, codified at Title 20, ch. 1 of the California Code of Regulations, the Commission takes official notice of the CEC's RPS Guidebooks and RPS draft Guidebooks, as posted on the CEC's official website, www.energy.ca.gov. (Unless otherwise noted, all further references to rules are to the Rules of Practice and Procedure.)

25 These include CMUA, PG&E, Sempra, and UCS. IEP agrees but believes that changes to the Eligibility Guidebook are also required.

26 These include CEERT, DRA, Marin Energy, and Noble Solutions (which argues that the appropriate date is the latest of the SB 2 (1X) effective date, this Commission's implementation decision, and CEC's revision of the Eligibility Guidebook).

27 The CEC is revising the Eligibility Guidebook. In the Staff Draft Guidebook, Renewables Portfolio Standard Eligibility (5th edition October 2011) (Draft Eligibility Guidebook), CEC staff has removed the prior discussion of requirements for "delivery," and has proposed that the CEC cease verifying "delivery" as of January 1, 2011. (at 63.)

28 These include DRA, GPI, Iberdrola, IEP, Ormat, and PG&E.

29 Although §399.16(c), setting the minimum and maximum requirements for each category, mentions "contracts executed after June 1, 2010," § 399.16(d), addressing procurement prior to June 1, 2010, includes "ownership agreements," a locution which applies to UOG. (See SCE opening comments at 23.) Section 399.16 should therefore be read to include UOG in a way most closely analogous to procurement contracts. The place of UOG in § 399.16(d) is discussed below.

30 These include BP, Calpine, DRA, GPI, Iberdrola, IEP, LS Power, Noble Solutions, Ormat, Sanitation Districts, TURN, and UCS.

31 These include PG&E, Shell, and WPTF.

32 These include LADWP and SCE.

33 These include AReM, CEERT, NV Energy, and TransWest.

34 In § 399.16(b)(1) and § 399.16(b)(3), more than one set of criteria is provided.

35 A number of parties participated in discussions that led to the development of the "RPS Product Matrix" in the Reference Proposal, which is attached to the comments of several parties. While this matrix does not necessarily reflect the views of any party, it makes the useful differentiation of the three distinct criteria within § 399.16(b)(1)(A).

36 Section 399.12(d) provides in full:

"California balancing authority" is a balancing authority with control over a balancing authority area primarily located in this state and operating for retail sellers and local publicly owned electric utilities subject to the requirements of this article and includes the Independent System Operator (ISO) and a local publicly owned electric utility operating a transmission grid that is not under the operational control of the ISO. A California balancing authority is responsible for the operation of the transmission grid within its metered boundaries which may not be limited by the political boundaries of the State of California.

37 Only Calpine, Northwest Energy Systems, and Ormat disagree.

38 CEC provides a useful map showing all balancing authorities with any California load in the Map of ISO and Non-ISO Balancing Areas in California, found at http://www.energy.ca.gov/maps/serviceareas/iso_non-iso_service_areas.html. This map therefore includes more balancing authorities than the statutory "California balancing authorities." See PG&E Comments at 8.

39 WREGIS Operating Rules (December 2010), at 3. The WREGIS Operating Rules may be found at http://www.wregis.org/uploads/files/854/WREGIS%20Operating%20Rules%20v%2012%209%2010.pdf. Pursuant to Rule 13.9, the Commission takes official notice of the WREGIS Operating Rules, as posted on the official WREGIS website, www.wregis.org. See also, Reference Proposal; CEERT Opening Comments.

40 Eligibility Guidebook (4th edition) at 29-30; see also discussion in D.10-03-021 at 21-24.

41 Draft Eligibility Guidebook at 66.

42 See Iberdrola comments at 8-9; Powerex comments at 6. In its Glossary of Terms and Acronyms, CAISO provides a definition of ancillary services that identifies the central role of the balancing authority. The glossary may be found at http://www.caiso.com/Pages/Glossary.aspx?FilterField1=Letter&FilterValue1=A&&&View=%7b02340A1A-683C-4493-B284-8B949002D449%7d. Pursuant to Rule 13.9, the Commission takes official notice of the CAISO Glossary, as posted on the official CAISO website, www.caiso.com.

In comments on the Proposed Decision, UCS suggests that a market in the provision of ancillary services by entities that are not balancing authorities is developing. The provision of true ancillary services (not substitute energy) by a non-balancing authority entity would not affect the fundamental requirements of this criterion, but would require the retail seller claiming procurement for RPS compliance in this category to document the provision of the ancillary services.

43 See, e.g., opening comments of Powerex (at 2), TransWest (at 6), and TURN (at 3).

44 CMUA, IEP, NV Energy, and SolarReserve argue that such scheduling should meet the criteria for this category; DRA, Duke Energy, LADWP, and PG&E disagree.

45 Duke Energy and SolarReserve argue that scheduling from off-site storage of renewable generation should also meet this criterion. The Commission is currently examining issues related to energy storage in Rulemaking 10-12-007. Until the Commission has set a more general framework for storage, it is premature to speculate on how storage will fit into the portfolio content regime set by SB 2 (1X). To the extent that there are basic issues of the RPS eligibility of storage resources, those issues are properly considered by the CEC.

46 SolarReserve, as well as Duke Energy and PG&E, make this argument.

47 It is not necessary to modify D.10-03-021 or D.11-01-025 in this regard. Energy Division may simply stop working on the role of direct transmission as explained in D.10-03-021, and is not required to produce any recommendations.

48 AReM, LADWP, NV Energy, SCE, and Shell address this point.

49 See, e.g., comments of SCE and TransWest. See also Res. E-4393 (April 15, 2011), approving an RPS procurement contract whose terms require that the generator's first point of interconnection with the transmission system will be with the CAISO balancing authority area, or that the energy will be dynamically transferred to the CAISO balancing authority area.

50 AReM, CMUA, California Wastewater Climate Change Group, Calpine, CEERT, CCSF, Sanitation Districts, Duke Energy, Evolution Markets GPI, IEP, LADWP, Noble Solutions, NV Energy, Ormat, PG&E, Powerex (in some circumstances), SDG&E, Sempra, Shell, Solar Alliance, SCE, and WPTF argue for inclusion; APS, CUE, DRA, enXco, Iberdrola, LSA, TURN (in some circumstances), TransWest, and UCS argue that unbundled RECs do not belong in this category.

51 Section 399.12(h)(1). WREGIS tracks RECs as WREGIS certificates. Each WREGIS certificate represents one MWh of RPS-eligible generation.

52 New § 399.12(h)(2), which is the same as prior § 399.12(h)(2), provides that a REC includes:

all renewable and environmental attributes associated with the production of electricity from the eligible renewable energy resource, except for an emissions reduction credit issued pursuant to Section 40709 of the Health and Safety Code and any credits or payments associated with the reduction of solid waste and treatment benefits created by the utilization of biomass or biogas fuels.

This provision is the same in the new and prior statute. New § 399.12(h)(3) changes the treatment of the use of nonrenewable fuels found in prior § 399.12(e)(3), but that is not relevant to this decision.

53 RPS compliance is counted in RECs. WREGIS denominates RECs by MWh. WREGIS calls the RECs in its system WREGIS Certificates. (Eligibility Guidebook at 6.)

54 In its comments on the PD, at 4, IEP asserts that a REC "should be thought of as a certificate that 1 MWh of energy was produced by an eligible renewable generation facility at a certain time and location, using a specific eligible technology or fuel." IEP supports this assertion by observing that the WREGIS Certificate specifies time, location, and fuel type for the RPS-eligible generation that the Certificate records. IEP provides no authority, however, for its transmutation of information recorded in WREGIS for verification purposes into part of the definition of a REC. Tacking such descriptive information on to the definition of a REC is contrary to the REC definition expressly set out in § 399.12(h) and its predecessor, prior § 399.12(e), as well as in D.08-08-028, and thus can not be used as a basis for interpreting § 399.16.

55 See, e.g., D.03-06-071; the staff white paper, "Renewable Energy Certificates and the California Renewables Portfolio Standard Program" (REC white paper) (April 20, 2006), found at http://www.cpuc.ca.gov/word_pdf/REPORT/55606.doc; D.06-01-019; D.08-08-028; and D.10-03-021 (where the terminology used was "tradable RECs").

56 See, e.g., Comments of Evolution Markets Inc. on Proposed Decision of ALJ Simon on Rulemaking to Implement the California Renewables Portfolio Standard Program April 15, 2009), at 4 ( filed in R.06-12-012):

Adopting the standard market term "unbundled REC" or simply "REC" will conform the terminology in California with the other states and provinces in the WECC.

57 See, e.g., comments of AReM, CUE, DRA, Duke Energy, Evolution Markets, enXco, GPI, IEP, LADWP, PG&E, TransWest Express, TURN, and UCS. See also Reference Proposal at 1.

58 This point is made by, among others enXco, SCE, TransWest, TURN, and UCS.

59 In §§ 399.16(c)(1), (2), and (3), respectively.

60 Pasadena Police Officers Assn. v. City of Pasadena, 51 Cal.3d 564, 576 (1990) [citations omitted].

61 In its reply comments, SDG&E cites a comment in the committee report of the Senate Energy, Utilities, and Communications Committee (February 15, 2010) for the proposition that unbundled RECs may be classified in any of the three portfolio content categories. That committee report, however, does not use terminology consistent with the terminology of § 399.16(b)(2) and § 399.16(b)(3) as enacted, nor does it effect any change in the language of SB 2.

62 In comments on the PD, Sanitation Districts make a similar argument. TURN and TransWest oppose this argument in their reply comments on the PD.

63 The August 2, 2010 version of what would become § 399.16(b)(3) reads:

Eligible renewable energy resource electricity products, or any fraction of the electricity generated, that do not qualify under paragraph (1) or (2), including unbundled renewable energy credits.

The August 16, 2010 version, with additions in italics and deletions in strikeout, reads:

Eligible renewable energy resource electricity products, or any fraction of the electricity generated, including unbundled renewable energy credits, that do not quality under the criteria of paragraph (1) or (2), including unbundled renewable energy credits.

IEP did not request that the Commission take official notice of these different versions of the text of SB 722. No party objected to IEP's citation of these versions, however. The Commission therefore takes official notice of them pursuant to Rule 13.9. (See Quintano v. Mercury Casualty Co. (1995) 11 Cal.4th 1049, 1062 n.5.)

64 AReM, Sanitation Districts, and CWCCG.

65 See, e.g., comments of AReM, Sanitation Districts, and California Waste Water Climate Change Group.

66 As discussed in section 3.5.1.1.3, above, the CEC is in the process of revising its approach to the RPS eligibility of customer-side DG.

67 This interpretation of SB 2 (1X) does not indicate any diminution of this Commission's consistent support for DG. (See, e.g., R.08-03-008 and R.10-05-004 implementing the California Solar Initiative; Application (A.) 10-03-010, setting a net surplus compensation rate; and R.11-09-011, addressing interconnection issues for DG.) It merely implements new statutory requirements.

68 See, e.g., comments on the PD by AReM/RESA, Pilot Power, Shell, and WPTF. None of the comments or reply comments on this point discuss the statutory authorization of a procurement entity, which could "enter into contracts on behalf of customers of a retail seller for electricity products from eligible renewable energy resources to satisfy the retail seller's renewables portfolio standard procurement requirements." (§ 399.13(f)(1).)

69 For IOUs, this is the date that Commission approval of the resale contract is final. (Standard Term and Condition (STC) 1 "CPUC Approval," D.08-04-009, Appendix A). For ESPs and CCAs, it is the effective date chosen by the parties and stated resale contract.

70 Although parties refer to e-Tags as "NERC e-Tags," the North American Electric Reliability Council (NERC) has transferred the e-Tag system to the North American Energy Standards Board (NAESB). NAESB's e-Tag information may be found at http://www.naesb.org/weq/weq_jiswg_etag_1.8.asp. This decision will refer to "e-Tags."

71 WREGIS Operating Rules (December 2010) at 28.

72 These include CMUA, LADWP, NextEra, PG&E, and Shell.

73 Examples are provided by CMUA, DRA, Iberdrola, and SCE, among others.

74 These are provided at A-2. The REC White Paper may be found at http://docs.cpuc.ca.gov/word_pdf/REPORT/55606.doc.

75 See Eligibility Guidebook at 37, n.61 (4th ed. Jan. 2011), found at http://www.energy.ca.gov/2010publications/CEC-300-2010-007/CEC-300-2010-007-CMF.PDF.

76 These include AReM, CEERT, CMUA, Shell, and WPTF.

77 The CEC staff has recently proposed revisions to the CEC Eligibility Guidebook that would eliminate the current section on "delivery," including the discussion of firmed and shaped deliveries. See Notice of Staff Workshop re: Guideline Revisions for RPS Implementation and Renewable Energy Program, Attachment A (Summary of Revisions to the RPS Eligibility Guidebook and Overall Program Guidebook) (Guidelines Revision Notice) (September 23, 2011), at 2; http://www.energy.ca.gov/portfolio/notices/index.html. This staff proposal is merely preliminary, but it suggests that the CEC's prior description of firming and shaping may not be maintained in its implementation of SB 2 (1X).

78 See, e.g., Reply Comments of Iberdrola, at 12.

79 See comments of LSA, NextEra, TransWest, TURN, and UCS.

80 The buyer is likely to be, but is not necessarily, the retail seller ultimately claiming the firmed and shaped procurement for RPS compliance. It may also be the entity providing firming and shaping services.

81 As explained in section 3.6.3, below, IOUs' initial contracts for substitute energy must run for a minimum of five years, or the length of the contract for RPS-eligible energy, whichever is shorter. Because the Commission does not regulate the rates of ESPs or CCAs, and does not review their RPS contracts, we do not require an initial contract for substitute energy of any particular duration. ESPs and CCAs must, however, comply with all other requirements for procurement to be counted for RPS compliance in accordance with § 399.16(b)(2).

82 These sections are discussed more fully, below, and will also be addressed in later decisions implementing SB 2 (1X).

83 These include AReM, CMUA, PG&E, SCE, Shell Energy, and WPTF.

84 See § 399.15(c).

85 See, e.g., PG&E's opening comments on the PD at 11.

86 See, e.g., Iberdrola's opening comments on the PD at 45.

87 In its reply comments, CCSF expresses concern about requiring a long minimum length for the substitute energy contract, because CCAs have limited ability to recover contract costs if customers return to bundled service. Since the five-year minimum duration will not apply to the contracts of CCAs, CCSF's concerns are resolved.

88 PG&E makes this suggestion in its opening comments on the PD.

89 Compare prior §§ 399.15(c) and (d) to current § 399.15(c).

90 For IOUs, this is the date that Commission approval of the resale contract is final. (STC 1). For ESPs and CCAs, it is the effective date chosen by the parties and stated in the contract.

91 See new § 399.13(a)(3)(A), which requires each retail seller to submit an annual compliance report that includes, among other things, "the current status of compliance with the portfolio content requirements of subdivision (c) of Section 399.16. . ."

92 Once the Commission implements the cost containment mechanism called for in new § 399.15(c), the upfront showing that must be made by IOUs on the cost of REC-only contracts may change.

93 SDG&E sought Commission approval for purchases of RECs from Cabazon Wind and Whitewater Hill via Advice Letters 2118-E (Oct. 28, 2009), 2188-E-A (June 2, 2011), and 2118-E-B (June 2, 2011). These advice letters were approved in Resolution E-4335 (October 20, 2011). SCE sought Commission approval for both a novation of the Mountain View contract and purchase of RECs in A.09-09-015. SCE's request is currently pending.

94 DWR informs the Commission, via letter to the assigned Commissioner and provided to the service list of this proceeding, that the DWR contract with Mountain View Power Partners, assigned to SCE, expired September 30, 2011. The Cabazon and Whitewater contracts assigned to SDG&E will expire at the end of 2013.

95 Parties in general refer to § 399.16(d) as a "grandfathering" provision, but this locution is not much more helpful to understanding than the statutory phrase itself. This decision will instead describe the specific actions or consequences that attach to the statutorily-created class of contracts signed prior to June 1, 2010.

96 The details of reporting and compliance determinations necessary to implement this provision will be addressed in a subsequent decision.

97 These include AReM, DRA, CMUA, Iberdrola, IEP,MEA, Noble Solutions, Shell, and WPTF.

98 This section applies to utilities that either have 30,000 or fewer customer accounts and have issued a certain number of RPS solicitations, or have 1,000 or fewer customer accounts and are not connected to any transmission system or CAISO. The first condition applies to the Bear Valley Electric Service unit of Golden State Water Company. The second applied to Mountain Utilities. Mountain Utilities has since been acquired by the Kirkwood Meadows Public Utility District. (D.11-06-032.) Mountain Utilities is therefore no longer a retail seller for RPS purposes.

99 This section applies to utilities (or their successors) having fewer than 60,000 California customers and either serving retail end-use customers outside of California or being located outside the CAISO and receiving the majority of their electricity from generation sources outside California. The first condition applies to PacifiCorp. The second applies to California Pacific Energy Company, the successor to the California assets of Sierra Pacific Power Company. (D.11-02-015; D.11-04-030.)

100 The fact that the first compliance period runs until the end of 2013 provides a little time for the development of compliance tools. RPS procurement, however, proceeds apace, with the IOUs having already developed their short lists from their 2011 RPS procurement solicitations.

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