III. Discussion
In D.05-11-025, we decided that the participation of ESPs, CCAs, small utilities, and multi-jurisdictional utilities in the RPS program was based on five core requirements:
o The requirement that 20% of retail sales come from renewable sources by 2010, as required by the Energy Action Plan;
o The requirement that all entities increase their renewable retail electricity sales by at least l% per year;
o The requirement to report their progress toward meeting RPS program requirements to the Commission;
o The ability to utilize the flexible compliance mechanisms; and
o The requirement that they be subject to the same penalties and penalty processes.
We opened this OIR to fill in the details and set the practical steps for fulfilling these requirements. In today's decision, we address ESPs and CCAs, as well as certain elements common to all LSEs obligated under the RPS program. We intend to turn to small utilities and multi-jurisdictional utilities shortly, and address the particularities associated with each that might require some adjustments to these general elements, including integration with the standards found in Pub. Util. Code § 399.17.17
A. Participation of Energy Service Providers
AReM filed the Proposal of AReM for the Participation of Electric Service Providers in the Renewables Portfolio Standard Program under the Framework Established in Decision 05-11-025 (AReM Proposal) on February 17, 2006, in R.04-04-026. AReM's membership includes a number of ESP respondents in this proceeding.18 The ALJ's March 27, 2006 ruling stated that an individual ESP not filing its own proposals would be deemed to have waived its right to file a proposal. No other ESP proposals have been filed; we therefore treat the AReM Proposal as the proposal for participation of ESPs.
AReM's Proposal may be summarized as:
a. ESPs should have no RPS compliance obligations prior to January 1, 2006.
b. The incremental procurement target (IPT) for ESPs should be the same as that for utilities, i.e., 1% per year.
c. The baseline percentage of RPS-eligible renewable resources should be set at zero for all ESPs, regardless of the percentage of renewables in the portfolio of an individual ESP.
d. Reporting obligations of ESPs and other LSEs should be fundamentally the same.
e. Verification of ESP compliance should be accomplished through a system of certifications by ESPs and generators, rather than the California Energy Commission (CEC) verification process.
f. Flexible compliance rules should be the same for ESPs and the large utilities.
g. Within the flexible compliance rules, ESPs should be able to avail themselves of a somewhat different set of excuses for noncompliance than those available to the large utilities.
h. The enforcement process for ESPs should be based on the use of an order to show cause, rather than the existing enforcement procedure.
i. The cap on the amount an ESP could be penalized should be lower than the cap on penalties for the large utilities.
j. Contracts of less than 10 years' duration (often called "short-term contracts") should be available for ESPs' RPS procurement obligations.
k. RECs unbundled from the underlying RPS-eligible energy should be available for ESP compliance.
Most commenters19 urge us to limit the variations between the RPS process for ESPs and the process for the large utilities.20 PG&E asks that, if we allow changes to the process for ESPs, those changes be extended to the large utilities. AReM argues that the commenters seeking limits are trying to turn back the clock, ignoring D.05-11-025.
We adopt none of these positions in full. We agree with AReM that we meant what we said in D.05-11-025 about allowing ESPs, CCAs, small utilities, and multi-jurisdictional utilities flexibility in meeting the five core requirements of the RPS program. We also limit the variations in this flexibility to those elements that are truly necessary to allow ESPs to participate successfully in the RPS program; flexibility that merely expresses ESP preferences is not required.
We begin our discussion by noting that SB 1078 created a phase-in process for procurement targets for ESPs, with the potential for an ESP to begin assuming its RPS obligations as early as January 2, 2003.21 We have not previously explained how compliance with those obligations will be structured and evaluated. SB 107 changes the initial date of ESPs' obligations to be January 1, 2006 across the board.22 Because of the short period of time between the date of this decision and the January 1, 2007 effective date of SB 107, we do not think it worthwhile to carry forward the prior phase-in structure for ESP obligations.
Thus, for ESPs, as for the large utilities, we must identify and quantify several initial elements. (See D.03-06-071, D.04-04-014, and R.04-04-026.) AReM urges that the statutory minimum IPT that we have applied to the large utilities should also apply to ESPs. We agree that the same measure should apply to all RPS-obligated LSEs. We also agree with the commenters23 that note that meeting only the minimum 1% IPT will not allow any ESP to attain the 20% goal by 2010. This elementary arithmetic fact is also acknowledged by AReM. We do not, however, adopt the proposal of TURN and UCS that ESPs be required to meet increased IPTs for each year leading up to 2010. The 20% by 2010 goal is clear; ESPs will either take the appropriate steps to meet the goal, or they will explain to us why their potential penalties for failing to meet the goal should be reduced.
We decline to adopt AReM's suggestion that ESPs' IPTs be calculated as 1% of their current year's retail sales, rather than their prior year's sales. This is a needless deviation from the uniformity of IPT and reporting obligations set out in D.05-11-025. It is not justified by AReM's observation that ESP retail sales are subject to potentially large fluctuations; the flexible compliance rules are designed to allow LSEs to make up for unanticipated shortfalls in actual deliveries over a period of three years. Nothing in the record suggests that this mechanism will be inadequate for ESPs' compliance needs.
In order to set the large utilities' annual procurement targets, the statute prescribes the relatively straightforward task of determining "an initial baseline. . . based on the actual percentage of retail sales procured from eligible renewable energy resources in 2001, and, to the extent applicable, adjusted going forward pursuant to subdivision (a) of Section 399.12." § 399.15(a)(3). AReM suggests that, regardless of their actual RPS-eligible portfolios, all ESPs be given a baseline RPS procurement amount of zero in order to protect them from the competitive handicap of having different procurement requirements among the individual ESPs. This suggestion appears to confuse the baseline amount (RPS-eligible renewable resources already procured in the baseline year) with the IPT (annual increase in RPS-eligible renewables of 1% of prior year's sales). All RPS-obligated LSEs must increase their procurement by at least 1% of the prior year's sales, but each LSE has a different renewable baseline. See D.04-04-026. 24
To the extent that AReM is arguing that zero is a reasonable approximation of the ESPs' renewable portfolios, we agree; as shown in their preliminary renewable portfolio reports, ESPs as a group provide about 0.25 percent of their retail sales from renewable sources. Nevertheless, AReM's argument is not sound. It is the individual ESP (as it is the individual utility or CCA) that is obligated to meet renewable procurement targets under the RPS program, not ESPs (or utilities or CCAs) as a group. ESPs, pursuant to SB 107, will be subject to RPS obligations beginning January 1, 2006.25 We therefore use 2005 as the year in which the ESPs' baseline RPS procurement is figured.26
We apply these methods to the simplified ESP obligations created by SB 107 and set out the calculation procedure for APTs and IPTs for ESPs in Appendix B, using figures for a hypothetical ESP. ESPs shall provide all necessary information to Energy Division for the calculation of baselines and procurement targets. The ALJ may issue any rulings necessary to facilitate the expeditious calculation of baselines and procurement targets.
When we organized the RPS participation of the large utilities in D.03-06-071, we acknowledged the lead time needed for their compliance by allowing them to defer their entire 2004 IPT obligations for three years, without need to show any of the excuses for shortfalls in actual deliveries as part of the flexible compliance rules. (mimeo., p.50, n.41). We will take the analogous step for the ESPs, allowing them to defer their 2006 IPT obligations for three years without explanation under the flexible compliance rules. Also analogous to our treatment of the large utilities, ESPs will be required to meet their RPS obligations for 2007 and later years, or invoke one of the excuses for shortfalls allowed by D.03-06-071.
Unlike the large utilities, however, ESPs do not need to seek our advance approval of their RPS procurement plans. As we pointed out in D.05-11-025,
this Commission does not set rates or rates of return for ESPs, or review their overall procurement plans. . .[and] has less overall control over how ESPs and CCAs operate than we do over how utilities operate. Also, to the extent we consider ESP and CCA operations, our concerns about their operations differ somewhat from our concerns about the operations of the investor-owned utilities. In the context of the RPS program, our primary concern is to ensure that ESPs and CCAs do in fact reach the goal of 20% renewable energy by 2010.27 We are, however, somewhat less concerned about the details of how they get there.
Therefore, we do not believe it is reasonable to require these entities to be subject to the exact same steps for RPS implementation purposes as the utilities we fully regulate.
Nor do we review ESPs' RPS procurement contracts for reasonableness, since we do not regulate their rates. 28
In D.05-11-025, we stated that ESPs, CCAs, small utilities, and multi-jurisdictional utilities were subject to the same reporting, flexible compliance, and penalty rules as the large utilities. Although AReM initially suggested that ESPs use a voluntary certification method of reporting, it appears that AReM now agrees that the reporting rules should apply to ESPs in the same way as to other LSEs. 29 All ESPs must therefore submit to Energy Division the reports required by our decisions, as well as participate in the CEC's verification process.30 Since we do not require that ESPs file annual procurement plans and we do not review ESPs' RPS procurement contracts, we need another way to review the basis of ESPs' compliance reporting. ESPs must, therefore, when and as requested by the Director of Energy Division, send copies of contracts on which they are relying for RPS compliance to Energy Division, for use with the CEC's verification reports in verifying ESPs' RPS reporting and compliance.31
AReM seeks changes to the flexible compliance and enforcement processes for ESPs. AReM's request for a separate ESP enforcement regime is both unnecessary and unwise. In addition to the obvious value of more efficient administration of the RPS program, uniformity of compliance and enforcement requirements serves the values of transparency of program administration, ease of public access to information about the RPS program, and fairness of any enforcement actions. 32
AReM's request for different enforcement procedures is based on a misunderstanding of our current procedures. Properly understood, our existing enforcement procedures apply to all LSEs the safeguards AReM urges us to develop just for ESPs. As we explained in D.03-06-071 and D.03-12-065, our process provides notice to the LSE of the potential noncompliance and affords the LSE four different types of options to manage the noncompliance: use of the 25% no-explanation-needed shortfall mechanism; presentation of one of the excuses for a shortfall greater than 25%; presentation of a different explanation for a shortfall greater than 25%; and proactive request to the Commission to allow a greater shortfall. (D.03-06-71, mimeo., p. 50.) No penalty can be imposed until we "consider the [LSE's] reasons for non-compliance and determine whether the reasons excuse the non-compliance. If they do not, we determine the actual penalty to be assessed." (D.03-12-065, mimeo., p. 15.)
This process makes it unnecessary to consider now AReM's request that the list of excuses for shortfalls set out in D.03-06-071 be augmented. If an ESP believes that its RPS procurement shortfall should be excused for some reason other than those listed in D.03-06-071, it is free to present that reason to us.
Finally, AReM suggests that the $25 million annual cap on penalties to be assessed (D.03-06-071, mimeo., p.51) be lower for ESPs than for the large utilities. We reject this suggestion. The penalty amounts are calculated on the basis of kilowatt hours (kWh) of renewable energy generation to which the people of California were entitled, but they did not receive. An ESP that does not meet its RPS targets is failing to provide renewable generation to its customers, exactly the same as a large utility. But, as we noted in D.06-03-023, all potential penalties for RPS noncompliance lie in the future. An ESP facing a penalty in the future would be free to argue that the full potential penalty amount is disproportionately large. We have no reason to consider that issue now.
We discuss AReM's proposals with respect to contracting flexibility, the use of RECs, and the availability of SEPs33 in the more general discussions of those topics, below.
B. Participation of Community Choice Aggregators
The possibility for local government bodies to create CCAs was established by Assembly Bill 117 (Migden), chaptered September 24, 2002.34 In D.05-12-041, the most recent decision in R.03-10-003, our proceeding to implement the CCA legislation, we set up a process for CCAs to develop and present to us their implementation plans. In D.05-11-025, we indicated that a CCA's RPS compliance plan should be included in its implementation plan.
To date, no CCA has been formed, though interest has been expressed in a number of localities. That interest is sufficiently advanced in a few areas that specific planning for CCAs has been undertaken. In this proceeding, CCSF and Chula Vista (collectively, CCA Parties), as the most active potential CCAs, were named as respondents; they have participated with a proposal, comments, and (for CCSF) testimony and briefs. Despite their work, the lack of any existing CCAs and the absence of other potential CCAs has left our record on matters related to CCAs less robust than we might wish. We agree with the CCA Parties that the CCA process is not sufficiently far advanced for us to be able to specify all the details of CCA participation in the RPS program. We also agree, as CCSF points out in its testimony and briefs, that planning for CCAs would be aided by some more detailed guidance on the RPS process for CCAs. We therefore elaborate on the fundamentals for CCAs described in D.05-11-025, while recognizing that this may not be the last word.
The CCA Parties propose that:
a. This Commission's jurisdiction over CCAs' RPS compliance is limited to the five specific areas mentioned in D.05-11-025.
b. CCAs' procurement plans are not subject to this Commission's review or oversight.
c. CCAs should be able to use a variety of procurement strategies to fulfill RPS goals.
d. CCAs should have the same methodology for APT and IPT as the large utilities.
e. Baseline renewable generation should not be determined for CCAs until after their initial year of operation.
f. Reporting should be similar for large utilities and CCAs.
g. Flexible compliance should be the same for CCAs as for the large utilities, except that compliance for CCAs should be based on a five-year "ramp up" period.
h. Penalties cannot be assessed on CCAs by the same mechanism set forth in D.03-06-071 and D.03-12-065.
Overall, we find many of the CCA Parties' proposals sensible and consistent with our prior decisions. In some areas, however, adjustment of the proposals is required.
As an initial matter, we do not take such a limited view of our authority as the CCA Parties suggest. They cite neither statutory authority nor any statements from D.05-11-025 that would suggest that our initial outline of CCAs' RPS participation in that decision is or must be the definitive, and definitively limiting, statement of our authority. In enacting SB 1078, the Legislature instructed us to determine the manner in which CCAs would participate in the RPS program. It did not provide a list of elements of RPS participation by CCAs that were outside our purview. Nevertheless, as we expressed in D.05-11-025 and D.05-12-041, our review of CCA's plans and processes for RPS compliance is more limited than that for utilities.
One area where our oversight is limited is CCAs' RPS procurement plans. We agree with the CCA Parties' interpretation of D.05-11-025, that a CCA will inform us of its RPS plans, but we will not have oversight of its RPS process. Thus, for example, a CCA will not be required to file annual procurement plans, but will be required to meet its APT annually. As explained more fully in the discussion of contracting, below, we also agree with the CCA Parties that a variety of contracting and procurement mechanisms may be utilized for RPS compliance.
The CCA Parties propose that a CCA's renewable procurement baseline amount be determined in its second year of operation, using information from its first year of operation. A CCA's second year of operation would be the first year of its RPS obligation. Its APT in this second year would consist of its initial baseline procurement amount plus its IPT, calculated as 1% of its first-year retail sales.35 We agree that this is a reasonable adaptation of the methodology of D.03-06-071 to a CCA start-up and authorize this manner of initiating a CCA's RPS procurement obligation.
The CCA Parties propose that they should report on their compliance once per year.36 We believe that CCAs, like ESPs, should use the same reporting formats and schedules as the large utilities. All CCAs must therefore submit to Energy Division the reports required by our decisions, as well as participate in the CEC's verification process. Because we will not review CCAs' RPS procurement contracts37, CCAs should send copies of contracts on which they are relying for RPS compliance to Energy Division, for use in verifying their reporting and compliance.38
The CCA Parties also raise a question about their reporting obligations in the situation in which a CCA purchases RPS-eligible power through an ESP. We clarify that the retail seller is the entity obligated under the RPS statute, and thus the retail seller (here, the CCA) is the entity that reports the acquisition of the RPS-eligible generation. To the extent that an ESP acts both as a retail seller (i.e., sells power to retail end-user customers) and as an intermediary between generators and retail sellers, the ESP should report only eligible RPS procurement relative to its own retail sales as part of its RPS compliance reporting.
The CCA Parties suggest a variation on the flexible compliance rules to provide a 5-year "ramp-up" compliance period for CCAs. Thus, if a CCA's first year of operation were 2009, it would not be subject to enforcement sanctions for missing the 20% goal (if indeed it failed to attain the goal) until 2014. The CCA Parties argue that both the likelihood that the first CCAs will begin operation close to 2010 and the likelihood that some CCAs would want to develop their own renewable generation sources, should lead to a compliance scheme based on a CCA's start-up date. If a CCA "loaded up" on existing renewable generation in order to meet the 20% by 2010 goal, the CCA Parties argue, it could be undermining part of its reason for existing. SCE claims that a five-year compliance window for CCAs should be unnecessary, since "[i]t is fairly easy for a start-up-particularly a carefully-planned start-up-to begin operation with 20% renewable power."39 SCE's assertion is not supported by the record, but it is reasonable to believe that a CCA in formation may have a range of renewable procurement options, since it is not tied to existing procurement or generation commitments.
We do not resolve the merits of this disagreement. First, we do not have the relevant information. We cannot predict when a CCA will commence its operations, and thus are unable to judge how or even whether it might be disadvantaged in RPS procurement. We also cannot predict the size of its retail sales (the basis for calculating its RPS obligations) after the statutorily-required period for customers to opt out of CCA service.40 As CCSF noted in its testimony, this complex statutory arrangement could lead a CCA's compliance situation to look rather different between the day it commences operation and its second anniversary of service.
Second, it is not appropriate to decide now on a separate compliance regime for CCAs. As we pointed out in D.06-05-039, "the 20% by 2010 action item is the policy of the state, not just the Commission." (mimeo., p. 28.)41 If a CCA believes that its RPS compliance status could be in jeopardy, it would have the option of seeking "to convince the Commission that a deferral [of an RPS obligation] would promote. . . the overall procurement objectives of the RPS program." (D.03-06-071, mimeo., p. 53.) We are confident that our existing process will allow us to take all relevant elements into consideration in any context in which a CCA may have compliance difficulties. 42
C. Contracting Issues
In D.06-03-016, we reaffirmed the statutory requirement that utilities must offer contracts of at least 10 years' duration in their RPS solicitations, and clarified that utilities may accept counteroffered contracts for less than 10 years, with our approval. We now turn to the details of applying that principle to the utilities, and the more general question of allowable RPS procurement contracts for all RPS-obligated LSEs.
At the hearing held in May 2006, witnesses were drawn from almost all groups with an interest in the RPS program: large utilities, ESPs, CCAs, renewable generation developers and marketers, consultants, public interest groups, and ratepayer advocates. They presented an array of evidence about renewable project development, contracting possibilities, procurement practices, and activities in other states.43 On the basis of this record, we conclude that we may allow, consistent with both the RPS statute and our prior decisions, more flexibility in contracting for RPS procurement than has previously been available.
The hearings opened with the example, provided by CEERT's witnesses, of a major renewable development in California that proceeded without a conventional long-term power purchase agreement (PPA) with a utility. FPL Energy constructed its High Winds project, a 162-megawatt (MW) wind farm in Solano County, after it secured a 30-year contract for the entire output of the project with PPM Energy (PPM), a subsidiary of Scottish Power. FPL Energy would not have built the project without a long-term agreement for the output with a buyer, though not necessarily a utility buyer. At the time it committed to the project, PPM did not have any buyers for the project's output. But PPM was able, without difficulty, to resell the entire output to various buyers, largely publicly owned utilities. PPM's contracts with the buyers covered a wide range of terms and lengths, including time periods shorter than 10 years.
It was the unanimous view of the renewables developers and marketers who testified (Messrs. Glader and Seymour for CEERT; Langenberg for Central California Power; Morrison for CalWEA; and Reese for GPI) that new renewable generation in California would almost always have to be supported by long-term contracts. The current reality of financing is that investors are not now willing to invest in renewable generation in California on any other basis. Another reality, as Morrison noted, is a California developer's strong preference to sell the output of the project once, rather than spend time and effort selling the output in pieces over a potentially extended period of time. The buyer of the entire output of the project does not necessarily have to be a retail seller; as GPI notes, PPM provides an example of how that role can be filled by another entity, acting as an intermediary between the generator and retail sellers.
The importance of long-term contracts for new renewables development is not simply the result of circumstances unique to California. In Texas, often adduced as an example of successful renewable generation development, more than 80% of the new wind generation in that state's RPS program was developed with long-term PPAs. States as diverse as Colorado, Oregon, Pennsylvania, and New Mexico show a similar pattern of long-term contracts for the output of new wind generation.44
Within the context of the continuing significance of long-term contracts, most witnesses and most parties argue that it is better to remove artificial barriers, such as minimum contract lengths, making it difficult for buyers and sellers of renewable energy to come to mutually agreeable terms. They provide a variety of examples of situations in which this could be useful. Some QFs whose contracts with large utilities are expiring may have less than 10 years remaining in their useful lives. A shorter term contract could keep such facilities producing renewable energy; it could also give them time to line up financing for repowering, if desired. The CCA Parties point out that a CCA might want to use short-term contracts while it is developing its own new renewable generation. Other circumstances may make it attractive for LSEs and generators to divide up access to new generation with a mix of long-term and short-term contracts.45
Nevertheless, there is no evidence in the record of any arrangements like these now in place in California for new RPS-eligible facilities. Nor is it likely that there will be many in the near future. Developers are strongly committed to obtaining long-term contracts. The large utilities are working to attain the 20% goal by 2010. As SCE points out, it is difficult to imagine a situation in which a large utility would, prior to 2010, take less than all the renewable output of a new facility on a long-term contract. It needs the energy both to meet the 20% by 2010 goal and to sustain its renewables purchases past 2010. Both PG&E and SDG&E support the general concept of contracting flexibility, but agree that its role is likely to be small (though welcome).
The approach we set forth below responds to the concerns of those parties that have argued that excessive reliance on short-term contracting is likely to have a negative impact on the construction of new renewable generation in California.46 In the abstract, this appears to be a cogent concern. Without a long-term contract for the output of a new renewable project (whether with an LSE or a marketer), few renewable developers would build new projects in California. Thus, this argument goes, allowing LSEs to rely on short-term contracts will stifle new RPS-eligible generation.
This fear, however logical, is not realistic. First, in D.06-03-016 we recently reaffirmed that utilities' RPS solicitations must offer contracts of at least 10 years in duration. Any shorter term contract proposal must be initiated by the bidding renewable developer. If the bidder believes that there is a place for the short-term contract in getting the project built, we believe that (within the limits we have expressed), the developer and the utility should be free to make that deal.
Second, there is no dispute that California will not reach the goal of 20% RPS-eligible generation by 2010 unless new generation is built and comes on line. There is also no dispute that long-term contracts are the dominant method of structuring new development so that it can be financed. It is also widely acknowledged that essentially all existing RPS-eligible generation in California is spoken for: whether in the RPS baselines of the utilities with contracts with RPS-certified renewable QFs; in the contractual delivery commitments of newly-built renewable generation; or in the generation from Calpine's Geysers facilities already in the portfolios of RPS-obligated LSEs. Merely delivering the generation to one LSE rather than another (as would occur if other LSEs began to acquire energy from a QF whose contract with one of the large utilities expired) does not change this reality.47 Even unbundled RECs, as UCS points out, have to come from somewhere, and that somewhere is actual RPS-eligible generation.
Thus, there is simply no plausible market situation in California in which short-term contracts for existing renewable power will crowd out long-term contracts for new generation. Many parties believe that short-term contracts could be helpful in providing additional tools not only for LSE compliance but also for the development of new projects. Our decision today allows them to put that belief into practice.
AReM advances a two-pronged argument that, independent of the feasibility or general utility of short-term contracts, ESPs must be able to use short-term contracts for RPS procurement. The first prong is an assertion that because ESPs currently have short-term contracts with their customers (lasting roughly six months to no more than three years), they must be able to match their RPS procurement to their current customer demand. The second prong is a claim that preventing ESPs from using short-term contracts to match existing customer demand would put publicly-traded ESPs in jeopardy of violating the requirements for internal control structures and financial reporting found in the Sarbanes-Oxley Act of 2002, Pub. L.107-204, 116 Stat. 745, and the implementing rules promulgated by the Securities and Exchange Commission.48
Neither of these reasons for special treatment of ESP contracting is supported by the record. There appears to be no imperative (as distinct from a business preference) for ESPs to have procurement contracts that closely match each customer contract. AReM's witness Hitt testified that Constellation NewEnergy is entering into renewable procurement contracts in New England that exceed the duration of its current customer contracts. CEERT witness Glader testified that the Board of Directors of PPM Energy approved a 30-year contract for the output of the High Winds project without any existing contracts to resell that output. Moreover, ESPs conduct their procurement virtually exclusively through bilateral contractual arrangements. This provides more flexibility than a solicitation process for an ESP to develop a portfolio of RPS contracts suitable for its business.
AReM's witness Hoekstra insisted that only an essentially one-to-one match between procurement contracts and customer contracts would allow an ESP to demonstrate the validity of its internal controls for Sarbanes-Oxley Act purposes. As noted above, both Ms. Hitt and Mr. Glader provided examples of ESPs that carefully considered entering into longer renewable procurement contracts than they had buyers for, and did so. Further, AReM's witness Counihan noted that both appetite for risk and risk management practices vary among ESPs nationwide. This demonstrated variation among ESPs vitiates Mr. Hoekstra's claim that very close matching of ESP procurement contracts to ESP customer contracts is legally required. Since, however, we conclude for other reasons that all LSEs should be able to use a variety of procurement contract approaches, the failure of AReM's claims for special treatment for ESPs' contracting needs has no practical impact.
We accept the parties' views that contracting flexibility is desirable, but that it is unlikely to serve as the basis for the development of very much of the new renewable generation needed to meet California's RPS goals. We will therefore allow a variety of contractual arrangements, so long as they are consistent with our requirements and consistent with the verification requirements of the CEC. We note that, as we incorporate SB 107's preconditions for approval of short-term contracts, we may need to revisit some aspects of our current process.
We will allow utilities to present for our approval, via advice letter, contracts offered by generators, in response to solicitations seeking long-term contracts for new RPS-eligible generation, that are for a period less than 10 years. The minimum length of such a contract also must be determined. The CEC currently sets three years as the minimum length for a utility's RPS procurement contract for which SEPs can be requested,49 but SB 107 makes any RPS procurement contract of less than 10 years categorically ineligible for SEPs.50 We therefore will allow utilities to accept as counteroffers in solicitations contracts of any length, as long as the contracts are at least one month in duration, to enable the CEC to verify RPS procurement claims. Making this change now, even though not all contracts from the utilities' 2005 and 2006 RPS solicitations are completed, should not have negative impacts. All utility RPS contracts are subject to our approval. Contracts resulting from counteroffers in the 2005 or 2006 solicitations that are shorter than three years would not, in any event, be eligible for SEPS; contracts of three up to 10 years would be subject both to our approval and the CEC's independent process for making determinations about SEP awards, if the generator applied to the CEC for SEPs.
All RPS-obligated LSEs are also free to enter into bilateral contracts of any length with RPS-eligible generators, as long as the contracts are at least one month in duration, to enable the CEC to verify RPS procurement claims. Bilateral contracts are of course subject to the general RPS reporting requirements of this Commission and the CEC. Such contracts are also subject to the rules for bilateral contracts and for the award of SEPs reviewed below.51
Additional steps must be taken before we may approve any RPS procurement contract of less than 10 years in 2007 and beyond. SB 107, in new §399.14(b)(2), prescribes that we must establish, for each retail seller, minimum quantities of eligible renewable energy resources to be procured either through contracts of at least 10 years' duration or from new facilities commencing commercial operations on or after January 1, 2005. We intend to address this task in this proceeding or in R.06-05-027, as the Assigned Commissioner deems appropriate.
If the potential of short-term contracting begins to be realized, we will also need a more robust method of evaluating the price of utilities' contracts of less than 10 years. Since the existing MPR calculation is based on a contract resulting from a utility solicitation of at least 10 years with the proxy gas-fired generation plant, it is not an appropriate yardstick. At the evidentiary hearing, there was only one suggestion for a short-term price evaluation tool: that perhaps existing short-term contracts for gas-fired generation could be used to develop a short-term MPR in accordance with § 399.15(a). Parties' comments evince a reluctance to engage in the development of another MPR, especially because short-term contracts will not, under SB 107, be eligible for SEPs.
We agree, however, with UCS that we need a tool for both contracts resulting from a utility solicitation and bilateral contracts negotiated by a utility that is more than an ad hoc review of each short-term utility contract. We are not convinced that a short-term MPR based on existing fixed price contracts for utility procurement would be more difficult to construct than it would be valuable in contract evaluation, but we have insufficient basis in the record to come to a conclusion about methodology. We therefore authorize the Assigned Commissioner and the assigned ALJ in this proceeding or in R.06-05-027, as the Assigned Commissioner deems appropriate, to seek information from the parties on the development of a shorter-term MPR or another price evaluation methodology for utilities' short-term contracts. We also remind the parties that, independent of the status of a price evaluation tool, SB 107 will condition our ability to authorize any contract of less than 10 year's duration on the development of the minimum procurement quantities from long-term contracts and/or new facilities set out in new § 399.14(b)(2).
Much of the parties' discussion of shorter-term contracts for RPS procurement has been framed by the utility solicitation rules established in § 399.14. Bilateral contracts, however, are in a different category. These contracts are not currently subject to the same requirements as those for solicitations-no matter what type of LSE enters into them. We note, however, that SB 107, in new § 399.14(b), may include short-term bilateral contracts in the category of contracts for which we are required to set new conditions for short-term contracts. We will explore this question as part of our implementation of new § 399.14(b), in this proceeding or in R.06-05-027, as the Assigned Commissioner deems appropriate.
For now, utilities' bilateral RPS contracts, of any length, must be submitted for approval by advice letter. Such contracts are not subject to the MPR, which applies to solicitations, but they must be reasonable (D.03-06-017, mimeo., p. 59). In addition, bilateral contracts between utilities and their affiliates are subject to the requirements of the use of an independent evaluator as set out in D.04-12-048.52
Bilateral RPS contracts of other LSEs must be submitted to Energy Division for reporting and compliance purposes, as noted above, but do not require our approval.
No bilateral contracts are currently eligible for SEPs. See D.03-06-071, mimeo., p. 59.53 SB 107, in new § 399.13(e), may remove this restriction and replace it with other requirements. We will look at this question as part of our implementation of new § 399.13(c), in this proceeding or in R.06-05-027, as the Assigned Commissioner deems appropriate.
The parties did not address the application of D.04-06-014, setting standard terms and conditions for RPS contracts, in their testimony. We think it is obvious, however, that all contracts for RPS-eligible generation (whether with large utilities, small utilities, multi-jurisdictional utilities, ESPs, or CCAs, and no matter what their duration) must ensure that RPS buyers and sellers are buying and selling the same thing, with the same environmental attributes, for approved contractual periods, with the same legal requirements related to basic contractual elements. The nonmodifiable terms and conditions were originally adopted to encourage statewide consistency and transparency of contracts that were the result of utilities' solicitations for RPS procurement. These goals remain valid for contracts for RPS procurement that are not the result of utility solicitations or bilateral utility contracts.54 We therefore will require, until further notice, that all RPS contracts of non-utility LSEs include the following sections from Appendix A to D.04-06-014 :
a. Definition and ownership of RECS;
b. Eligibility;
c. Assignment;
d. Applicable law.
We recognize that SB 107 requires that we revisit the standard terms and conditions we approved in D.04-06-014. (See, e.g., new § 399.14(a)(2)(D).) We therefore make our mandate that the above terms and conditions be included in all non-utility RPS procurement contracts provisional, with the possibility that it will change as we incorporate the changes to standard terms and conditions made by SB 107.
D. "Unbundled" RECs
Following our conceptualization in D.05-11-025, the REC white paper defined a distinction between "unbundled RECs" and "tradable RECs." We adopt this definition and set it out at length because of its importance to our discussion.
Under an unbundled REC regime, claim over the renewable attributes of energy produced by eligible renewable technologies can be transferred from the renewable generator to one LSE while the energy is delivered to another. However, once this transfer occurs, claim over the attributes cannot be resold. In contrast, under a tradable REC regime, although the concept of selling the energy and claim over the attributes to different parties remains intact, RECs may be transferred from the renewable generator to any third party, not just obligated LSEs. In addition, these attributes can be resold subsequent to the initial sale. REC white paper, p. 1, n. 1. 55
We further distinguish between an unbundled REC transaction, defined above, and the RPS delivery flexibility that we developed in D.05-07-039 and D.06-05-039. The former decision allows delivery to any point in the CAISO control area; the latter allows delivery to any point in California. As we noted in those decisions, the retail seller would be able to make reasonable commercial arrangements, such as swaps and remarketing, to manage any risks associated with a delivery point remote from its load.56 We continue to endorse the use of flexible delivery points, as set out in those decisions.
In an unbundled REC transaction, by contrast, instead of the RPS-obligated LSE taking the remarketing risk of the transaction, the entire remarketing risk lies with the generator. The LSE receives the REC and uses it for RPS compliance, and the generator is left with the commodity energy.
In a tradable REC transaction, the REC can also be sold separately from the energy. Unlike the unbundled REC transaction, however, the REC can be sold to any third party, not just an RPS-obligated LSE. Moreover, the REC may be sold any number of times, until it is finally counted for RPS compliance or otherwise retired.
In their comments on the REC white paper, many parties viewed unbundled RECs as a way-station to, or a form of, tradable RECs.57 Their opinions on unbundled RECs are therefore in large measure based on their views of the practicality, legality, and desirability of using tradable RECs for RPS compliance purposes.
CEERT shows the greatest enthusiasm for unbundled REC transactions, arguing that unbundled REC purchases will be useful in meeting the statewide RPS goals, by aiding at least some renewable development in transmission-constrained areas. CCSF and DRA also support the use of unbundled RECs. GPI points out that allowing unbundled REC transactions would probably not have a great deal of impact on the attainment of the 20% by 2010 goal, but might be useful in some circumstances. UCS cautions against setting up a potentially complex and labor-intensive system for monitoring and reporting unbundled REC transactions while the CEC is in the process of developing its Western Renewable Energy Generation Information System (WREGIS) system for REC accounting.58
AReM strongly urges that (tradable) REC transactions be allowed immediately. We are, as described above, allowing ESPs to carry a deficit of up to 100% of their 2006 IPT for up to three years without explanation. Thus, there is no immediate compliance crisis for ESPs that would strengthen AReM's case. On the contrary, as AReM points out, ESPs typically have contracts of less than two years' duration with their customers; thus, they will be able to work on their RPS procurement for 2007 and 2008 without being completely tied down to existing contracts. Moreover, SB 107, in new § 399.16, creates a number of requirements for a tradable REC system that cannot be set up instantaneously.
On balance, neither any party individually, nor the parties as a group, provided sufficient information and analysis for us to be confident that we should undertake the development of an unbundled REC methodology. For example, no party addressed the issue of valuation of unbundled RECs for purposes of utility cost recovery. This less-than-robust record may be a reflection of parties' focus on fully tradable RECs, but it may also indicate that unbundled REC transactions, standing alone, are not perceived as solving any significant problems for RPS-obligated LSEs or RPS-eligible generators that have not already been solved by flexible delivery. We will therefore not try to craft a process for allowing unbundled REC transactions at this time. Instead, we will return to REC-based transactions as a whole when we examine the potential use of tradable RECs for RPS compliance, in the context set by SB 107. 59
Because we conclude that we will not at this time allow any unbundled REC transactions, we do not address PG&E's arguments that we should allow unbundled REC transactions with generators located outside California.
E. Firmed and Shaped Transactions
Firming and shaping are methods of using other generation resources to supplement the delivery of power from intermittent renewable (in this case) resources.60 The use of firming and shaping may be relevant to the eligibility of the energy for RPS purposes. Such eligibility determinations are the province of the CEC. The CEC's requirements are set out at length in the CEC's Renewables Portfolio Standard (RPS) Eligibility Guidebook, publication # CEC-300-2006-007-F, adopted April 26, 2006.61
The ALJ sought comment on the availability and use of shaped or firmed transactions in California. The parties identified no shaped or firmed products for renewables that are currently offered commercially in California, though individual generators may make shaping or firming arrangements with individual customers. Parties also noted that, through its Participating Intermittent Resources Program (PIRP), the California Independent System Operator (CAISO) provides services that manage intermittent resources in the CAISO grid.62 The parties appear generally to be satisfied with CAISO's management of in-state intermittent renewable generation. We therefore conclude that there are no existing impediments to the use of in-state shaping and firming arrangements for RPS purposes-provided that the CEC's requirements for generator eligibility, delivery eligibility and verification are met.
PG&E has made extensive comments on the practical desirability and legal necessity of allowing RPS eligibility for firmed or shaped energy from transactions with out-of-state generators. We do not consider these arguments here, because PG&E has not provided any indication that the types of transactions it discusses are considered to be RPS-eligible by the CEC, both with respect to the eligibility of the generator and to the nature of the delivery arrangements.63
F. Supplemental Energy Payments
Issues related to SEPs have been raised in several contexts relevant to this decision. We briefly review the rules for SEPs and the authority to make various decisions about SEPs, both to complete our discussion of contracting options and to provide the context for our approach to the specific proposals about SEPs made by AReM and the CCA Parties.
The basic function of SEPs is "to cover the above market costs of renewable resources as approved by the Public Utilities Commission and selected by retail sellers to fulfill their [RPS] obligations. . ." Pub. Res. Code § 25743(b)(1). SEPs may be awarded by the CEC to new renewable generation facilities that meet the criteria set out in Pub. Res. Code § 25743 and the CEC's New Renewable Facilities Program Guidebook.
Bilateral contracts are not now eligible for SEPs. Since ESPs overwhelmingly use bilateral contracts, there is no current method for reviewing ESPs' contracts for purposes of SEP awards. Similarly, because CCAs do not yet have a contracting modality, we have not developed a method for reviewing CCAs' contracts for purposes of SEP awards.
SB 107, however, makes significant changes to the SEP process, both restricting the length of contract eligible for SEPs and expanding the pool of LSEs' contracts which may be eligible for SEP awards. To the extent that these changes implicate our own RPS contract review processes, we will explore revisions to our processes in this proceeding or in R.06-05-027, as the Assigned Commissioner deems appropriate. We note, however, that the key functions of developing eligibility criteria and actually awarding SEP funds remain the province of the CEC.
The CCA Parties suggest that the availability of SEPs be allocated among LSEs on a pro rata, cents per kWh basis. This proposal is more properly addressed to the CEC, which has the statutory authority to allocate SEPs, and "may establish caps" on SEP awards. (Pub. Res. Code § 25743(b)(1)(A)).
17 All subsequent references to sections refer to the Public Utilities Code, unless otherwise specified.
18 APS Energy Services Company, Inc.; Commerce Energy, Inc.; Constellation NewEnergy, Inc.; Sempra Energy Solutions; and Strategic Energy, LLC.
19 Aglet, DRA, SCE, and TURN and UCS.
20 The "large utilities" are PG&E, SCE, and SDG&E.
21 `Retail seller' means an entity engaged in the retail sale of electricity to end-use customers, including any of the following: . . .
(3) An electric service provider, as defined in Section 218.3, subject to the following conditions:
(A) An electric service provider shall be considered a retail seller under this article for sales to any customer acquiring service after January 1, 2003.
(B) An electric service provider shall be considered a retail seller under this article for sales to all its customers beginning on the earlier of January 1, 2006, or the date on which a contract between an electric service provider and a retail customer expires...
22 See new § 399.12(h)(3).
23 DRA, SCE, TURN.
24 The baseline renewable procurement in a hypothetical ESP's portfolio is shown in Appendix B.
25 ESPs may carry a deficit of up to 100% of their 2006 IPT without explanation for up to three years.
26 For any ESP not registered in California in 2005, we will use the first year of its registration.
27 The annual procurement targets are a means of ensuring that goal is reached in a relatively orderly fashion.
28 SB 107 makes significant changes in the requirements for awards of supplemental energy payments (SEPs) and the approval of RPS procurement contracts of less than 10 years' duration. As we implement those provisions, we may address the issue of whether ESPs, as well as other LSEs, must provide additional or different pre-procurement information and analysis than is now required. SB 107 may also lead to Commission review of ESPs' contracts that may be eligible for SEPs. These issues will be taken up for further development in this proceeding and/or R.06-05-027.
29 Because this is no longer a contested issue, we do not address the objections to the voluntary certification proposal made by TURN and UCS.
30 See Renewables Portfolio Standard Procurement Verification Report, final report adopted February 1, 2006, Publication No. CEC-300-2006-002-CMF. The report may be found at http://www.energy.ca.gov/portfolio/documents/index.html.
31 If any ESP seeks confidentiality protection for information contained in any RPS procurement contracts submitted to Energy Division, it shall comply with the substantive and procedural rules set forth in D.06-06-066, the Commission's recent decision in its Confidentiality proceeding, R.05-06-040, and any subsequent decisions issued in the same or successor proceeding. The extent of confidential treatment accorded to ESP RPS contract materials is addressed in Appendix 2 (ESP Matrix) to D.06-06-066.
32 We reserve here the questions of what, if any, adjustments to this general principle should be made for the situations of small utilities and multi-jurisdictional utilities. We will address them in a subsequent decision.
33 SEPs are authorized in § 399.13(c), which requires the CEC to "[a]llocate and award supplemental energy payments pursuant to Chapter 8.6 (commencing with Section 25740) of Division 15 of the Public Resources Code, to eligible renewable energy resources to cover above-market costs of renewable energy." SB 107 moves this authorization to new § 399.13(e) and adds new requirements, as discussed more fully in the section on SEPs, below.
34 CCAs are defined in § 331.1.
35 CCAs may carry a deficit of up to 100% of their first IPT without explanation for up to three years, subject to the further development of the flexible compliance rules in accordance with SB 107. See new § 399.14(a)(2)(C).
36 To the extent that this proposal was motivated by a desire to keep compliance reporting separate from annual procurement planning, we note our resolution of that issue in Section III.B.1., above.
37 As we noted with respect to ESPs, SB 107 makes significant changes in the requirements for awards of SEPs and the approval of RPS procurement contracts of less than 10 years' duration. As we implement those provisions, we may address the issue of whether CCAs, as well as other LSEs, must provide additional or different pre-procurement information and analysis than is now required. SB 107 may also lead to Commission review of CCAs' contracts that may be eligible for SEPs. These issues will be taken up for further development in this proceeding and/or R.06-05-027.
38 If any CCA seeks confidentiality protection for information contained in any RPS procurement contracts submitted to Energy Division, it shall comply with the substantive and procedural rules set forth in D.06-06-066, the Commission's recent decision in its Confidentiality proceeding, R.05-06-040, and any subsequent decisions issued in the same or any successor proceeding.
39 SCE's Response to Proposals for Renewables Portfolio Standard Participation (March 7, 2006), p. 6.
40 See § 366.2(c)(11)-(13).
41 SB 107 includes this goal in amended § 399.11(a).
42 The CCA Parties also take too alarmist a view of the role of penalties in our RPS enforcement process. There is simply no basis for their assertion that "a penalty process as to CCAs presents the obviously unworkable possibility that the Commission could fine individual elected officials. . ." (CCA Parties' Proposal, p. 26.) All of our discussions of the compliance and enforcement process make clear that the relevant entity for enforcement purposes is the RPS-obligated LSE, not any individual. (See D.03-06-071, D.03-12-065, and D.06-03-016.)
43 A list of witnesses submitting testimony is found in Appendix C.
44 This information was provided by TURN witness Freedman. It was not contradicted at the hearing.
It is not easy to evaluate information about practices in other states, since the RPS requirements and underlying electricity markets may differ from California's, and among other states. However, information that has relatively few variables embedded in it, such as Table 2 in TURN witness Freedman's testimony (new wind generation information) or AReM witness Hitt's list of projects with which Constellation NewEnergy has entered into long-term contracts, is easier to evaluate than information that has many variables embedded in it. For example, Table 2, "Planned New Renewable Resources in States with RPS Policies," in AReM witness Counihan's testimony, uses information from two different sources with different criteria for inclusion, and does not provide a basis for understanding what factors contributed to the different projected resource additions in different states.
45 This was referred to in the hearing as analogous to an "anchor tenant" in a real estate development: a developer would have one large, long-term customer, and be able to sell to a number of small, shorter-term customers as well. There are currently no anchor tenant-type arrangements for new renewable generation in California.
46 Aglet, DRA, TURN, and UCS are in this group.
47 SCE's testimony made clear that even if all of SCE's QFs with contracts expiring between now and 2010 signed new contracts with ESPs or other obligated entities, there are too few expiring QF contracts to cover the RPS needs of ESPs in SCE's service territory. And SCE does not concede that it would lose all the QFs with expiring contracts. Although PG&E did not provide similar information on expiring QF contracts, its witness did note that PG&E makes a planning assumption that it will retain about 80% of the QFs whose contracts expire-leaving only a small proportion potentially available to other RPS-obligated LSEs.
48 Section 404 of the Sarbanes-Oxley Act provides, in relevant part:
The Commission shall prescribe rules requiring each annual report required by section 78m(a) or 78o(d) of this title to contain an internal control report, which shall-
(1) state the responsibility of management for establishing and maintaining an adequate internal control structure and procedures for financial reporting; and
(2) contain an assessment, as of the end of the most recent fiscal year of the issuer, of the effectiveness of the internal control structure and procedures of the issuer for financial reporting.
15 U.S.C.A. § 7262(a).
49 New Renewable Facilities Program Guidebook, Seventh Edition, publication # CEC-300-2006-006-F, adopted April 26, 2006, found at http://www.energy.ca.gov/renewables/documents/index.html#rps, p. 4.
50 Section 16 of SB 107 amends § 399.14. This restriction is found in new § 399.14(b)(1).
51 SB 107 authorizes the award of SEPs for procurement contracts of at least 10 years of non-utility LSEs, conditioned on the demonstration that certain additional conditions have been met. See SB 107, section 6; new Pub. Res. Code § 25743(b)(F).
52 These requirements were extended to RPS solicitations in D.05-07-039 and D.06-05-039, but we have not previously noted their application to utilities' bilateral RPS contracts.
53 Since bilateral contracts are not now eligible for SEPs, the question of inadequate SEPs to cover above-market renewable contract costs, one of the four excuses for IPT shortfalls greater than 25%, does not arise in the bilateral contract context. (See D.03-06-071, mimeo., p. 50.)
54 Utilities' RPS contracts remain subject to D.04-06-014, unless and until revisions to the standard terms and conditions are made.
55 Because several parties expressed concern about this issue in their comments, we reiterate here that the white REC paper "will provide the basis for exploration of [REC] issues, but will not be the final word." R.06-02-012, mimeo., p. 9. We do not intend to adopt categorically the REC white paper or make it the basis of this, or any other, decision. We treat it as a comprehensive presentation by staff on a wide range of issues related to RECs. If we intend to rely on any part of the REC white paper, we will make our reliance explicit, as in our adoption of the definitions we quote in the text. It is therefore unnecessary to require any revision or correction of the REC white paper, as some parties, including CEERT and GPI, have urged.
56 In giving these examples, we do not intend to limit the types of commercial arrangements LSEs and generators may use to mange these risks.
57 They include AReM and WPTF, California Manufacturers and Technology Association and California Large Energy Consumers Association, California Solar Energy Industries, et al., IEP, Pilot Power Group, Powerex Corp., SDG&E, and Sustainable Conservation.
58 In § 399.13(b), the Legislature gave the CEC the responsibility to develop "an accounting system to verify compliance with the renewables portfolio standard by retail sellers. . ." For information about the WREGIS system, see http://www.energy.ca.gov/portfolio/wregis/index.html. SB 107 makes significant additions to the CEC's responsibilities for REC accounting in new §§ 399.13(b), (c), and (d).
59 Investigation of a tradable REC system was identified in the scoping memo as one of the tasks for this proceeding, which will now necessarily include integration of the requirements of SB 107.
60 See Appendix A to the REC white paper.
61 Found at http://www.energy.ca.gov/renewables/documents/index.html#rps.
62 See "PIRP FAQs, Part 1," http://www.caiso.com/17d0/17d0c24717130.html.
63 We note that SB 107, in new Pub. Res. Code § 25741(a), directs the CEC to consider firming and shaping of out-of-state renewable resources in developing its criteria for eligibility of delivery methods for RPS-eligible generation.
