3. Procurement Process Issues
3.1. PRG
Procurement Review Groups (PRGs) were initially established in D.02-08-071 as an advisory group to review and assess the details of the IOUs' overall procurement strategy, RFOs, specific proposed procurement contracts and other procurement processes prior to submitting filings to the Commission as an interim mechanism for procurement review. PRG recommendations are advisory and non-binding, and no participants in the PRG process give up any rights associated with future litigation of issues addressed in PRG meetings.
The Commission has consistently acknowledged the value of PRGs by ordering their continued use, so they continue to advise IOUs on their procurement activities.136 Current Commission orders require IOUs to meet with the PRG (1) quarterly to review their portfolio position and transactions and (2) as needed to review all transactions with terms greater than three months.
PRGs review procurement activities including, but not limited to:
· RFO development
· Bid evaluation and ranking
· Gas supply plans
· Hedging strategies
· Consumer Risk Tolerance (CRT) triggers
· Nuclear fuel plans
· Congestion Revenue Rights
· New technologies
· Procurement portfolio position and transactions (on a quarterly basis, as noted)
With some exceptions, the same individuals and organizations make up the PRGs for each of the three IOUs (e.g., DRA, TURN, Aglet, UCS, ED, DWR). PRG members participate in separate meetings with each IOU and are tasked with staying abreast of the many issues noted in the above list for each IOU. As it is a considerable task to manage the significant amount of data and other information, PRG participants who are also intervenors in this proceeding have proposed a number of process improvements, which are discussed in this subsection.
In addition, PG&E requested a change to the PRG consultation threshold for transactions with a term greater than three calendar months, some parties have raised transparency concerns related to the PRG process and representatives of DA have requested that non-market participants including DA and CCA representatives be present at PRG meetings that address resources that will be subjected to the CAM. The issues are also addressed in the subsection.
Besides the required quarterly PRG meetings, the IOUs frequently schedule meetings for the various reasons listed above. DRA has requested that each IOU develop a monthly calendar on a quarterly basis that identifies the planned meetings and procurement issues to be addressed.137 SCE finds this request reasonable provided it leaves the IOUs flexibility to update the calendar as needed, including organizing a PRG meeting even if it is not on the calendar.138 PG&E stated they would willingly provide a calendar of planned meetings and solicitation activity.139 The IOUs cite scenarios such as issuance of RFOs, bidder's conference, bid deadlines, and other procurement activities that by their nature are, at times, scheduled upon short notice.
We concur with DRA's suggestion that a PRG calendar would be a useful process tool. Further, to address the issue of scheduling of conflicting PRG meetings, we direct the IOUs to individually set up and maintain a web-based PRG calendar that can be accessed and updated by the IOU. This will enable each IOU to efficiently schedule meetings with full knowledge of other IOU PRG meeting dates and times.
Scheduling PRG meetings requires planning and coordination with all PRG members; maintaining these PRG calendars will be part of that planning. The calendar will also include dates of expected solicitation milestones (RFO release dates, bid deadlines, etc.). To maintain the confidential nature of PRG data, though, calendar content shall be restricted to non-confidential information.140
DRA recommends that for each PRG meeting, the IOUs develop an agenda to include the meeting date and time, and a list of issues covered in the meeting with a brief description of each issue. DRA also suggests a "standard" format for PRG meeting presentations that includes an introductory page explaining the purpose and background of the presentation, and a conclusion page describing next steps.141
DRA claims that there have been times in the past where PRG members received PRG materials only a few hours or one day before the meetings. "The materials are, by necessity, typically very technical requiring sufficient time to adequately review the material and provide useful feedback to the IOU."142 DRA therefore requests that meeting materials be distributed five days in advance. Aglet testified that PRG members often received materials less than two days ahead of meeting times and recommended that meeting materials need to be distributed at least two days in advance.143
PG&E agrees that PRG participation is improved if parties have the opportunity to review written material in advance. PG&E agrees that providing meeting materials two days in advance is a reasonable goal, but notes that when 48 hours advance distribution is impossible, they attempt to provide PRG members sufficient opportunity to understand the written material and provide their feedback.144 SCE is concerned that strict meeting material deadlines would be difficult to meet in consideration of some procurement process that requires PRG consultation. RFO bid closing windows and bid acceptance are sometimes on a quick 24 to 48-hour interval that precludes providing PRG members accurate updates 48 hours before a meeting.145
There is presently no formal agenda requirement for PRG meetings. PRG members often participate in several PRG meetings over a short period of time (sometimes three or more meetings with different IOUs in a one-week period). Also, in light of the PRG's responsibility to advise and review IOU procurement activities, preparation for PRG meetings is imperative. Meeting materials such as presentations, data sheets, or summaries must be reviewed and analyzed to develop informed opinions and lines of inquiry in advance of the corresponding PRG meeting. Providing an agenda and meeting materials with sufficient lead time will aid PRG members in effectively organizing and focusing their participation.
Consequently, we direct the IOUs to provide PRG members with meeting agendas and materials a minimum of 48 hours in advance of the PRG meeting, unless there are unusual, extenuating circumstances that the IOU communicates to PRG members in an email announcing a meeting or distributing meeting materials on a tighter timeframe.
Aglet requests that the IOUs provide PRG meeting minutes and a "to do list" when PRG members ask for additional information during a meeting.146 While DRA understands preparing PRG minutes could be difficult, it recommends a minimal requirement that the IOUs prepare a list of the participants and issues discussed after each PRG meeting.147 PG&E has no objection to minutes.148 SCE testifies that memorializing PRG discussions and party positions in accurate minutes would jeopardize the free flow of opinions and ideas due to concerns that it could become evidence in a future legal argument.149
We agree that providing a post-PRG meeting summary will further facilitate efficient and effective use of the PRG. We adopt DRA's recommendation the IOUs provide (confidential) meeting summaries to PRG members. Meeting summaries will include a list of attending PRG members, including the organizations represented, a summary of topics presented and discussed, and a list of information requested or offered to be supplied after the meeting, (and identify the requesting party). We do not require the IOUs to develop detailed PRG meeting minutes in this decision, and we also stress that this information is in no way admissible in hearings as evidence or able to be cited in testimony.
Parties that are not part of the PRG raised concerns that IOU procurement conducted in consultation with the PRG exists in a "black box" of secrecy since the nature, content, and results of PRG meetings are confidential. This issue was further explored in the May 2007 ED workshops, and most of the concern revolved around who was on the PRGs and what was accomplished in the process.
As a result, a PRG Transparency working group was formed consisting of CPUC staff, PRG members, non-PRG members and representatives of the IOUs. The working group met several times with the goal of making this "black box" less opaque. To make the PRG process less mysterious, working group participants agreed that the IOUs could provide the following information to the public:
1. The date and meeting time that a specific PRG meeting occurred and the duration of the meeting;
2. The individuals participating in the PRG meeting, and the organization that the individual represents (e.g., TURN, Aglet, etc.); and,
3. A list of items discussed during the meeting, including only public (i.e., non-confidential) information.
We adopt the Transparency Working Group's information-sharing proposals, and recommend that the IOUs work together to incorporate this information into the web-based calendar or another web-based forum, and provide this information to this and future LTPP proceeding service lists.
D.06-07-029 provides the IOUs with a mechanism to recover procurement costs for system reliability resources from all customers in the system, bundled and unbundled. This subsection addresses the fact raised by some intervenors that no DA- or CCA-specific representatives are currently participants in PRG meetings.
AReM contends that the goal of fairness to all customers would be served by including DA and CCA customer advocates on each IOU's PRG. AReM supports a proposal for expanding the PRG as a fair and responsible way to protect the interests of customers who are asked to bear the costs of system resource procurement.150
DACC points out that all three IOUs speak highly of their PRGs and the PRG process. DACC notes that until the adoption of D.06-07-029, the utilities have not procured new resources on behalf of direct access customers, and thus DA input was not needed. DACC argues that this has changed dramatically with the adoption of D.06-07-029, and that now DA customers should be explicitly represented on each of the PRGs.151
CCSF agrees with the DACC proposal that since DA customers will be paying for capacity procured by the IOU's, they should have a representative on each of the IOU PRGs. The CCSF argues that the same argument holds for customers of CCAs. Since CCA customers will also be paying for capacity procured by the IOUs, CCAs also should have customer representation on the IOU PRGs.152
SDG&E testified that if the Commission finds the need for additional PRG members from CCA and DA customers, it is essential that the following limits be placed on any benefiting customers' involvement: (1) if benefiting customers are allowed to participate in the PRG, it should only be for discussion of any supply procured on behalf of those customers (i.e., there is no need for unbundled customer representatives to be involved in any IOU procurement matters unrelated to the contracts subject to D.06-07-029), and (2) benefiting customer involvement should be allowed only to the extent that any attendee warrants that it will not bid, or assist others in bidding, in the resulting energy auction.153
SCE testified that D.06-07-029 fairly allocates procurement of new generation to all benefiting customers. SCE claims they do not engage in excessive procurement that would burden all system customers and that should they do so, the existing PRG members would object.154
A PRG Participation Working Group consisting of representatives of DA and CCA customers and organizations, PRG members, and Commission staff met several times to determine if and how CCA and DA customers could be explicitly represented in the PRG process. The working group determined that the existing PRG does not include participants that solely represent CCA and DA customers. The working group proposed the creation of a new advisory CAM Group supplemental to the PRG.155 The new CAM Groups would include existing PRG members, CCA and DA customer representatives, and representatives of any other non-bundled customers established in future Commission policies. The working group's proposal to create the CAM Group is presented in Attachment D.
The proposal states that the CAM Group would be called upon when an IOU plans to procure new generation resources and recover the costs of the resources through the CAM, or when an IOU, at the time it decides to seek new generation, has not decided its cost recovery basis, bundled or non-bundled. When an IOU plans to procure and recover costs solely from bundled customers, the PRG would continue to be the IOU's advisory group. When an IOU plans to procure and recover costs using the CAM, or has yet to determine this at the time of initiating an RFO, an IOU would notify the ED and the CAM Group participants.
The CAM Group would operate as the PRG does except it will review activities and information isolated to procurement that will or may use the CAM, and the IOUs will not be required to meet quarterly with the CAM Group. The CAM Group would have the same privilege to request and receive additional information of the IOUs, just as PRG members do for bundled procurement related processes.156
The CAM Group would be composed of existing PRG members, Commission staff, and a reasonable number of end use non-bundled customers or individuals hired to represent their interests.157 CAM Group members would be subject to a Non-Disclosure Agreement ("NDA") developed specifically for the CAM Group.158 CAM Group members who are not part of the existing PRG who are authorized for intervenor compensation would qualify for compensation for CAM Group participation pursuant to Commission rules governing such compensation, and PRG members who receive such compensation would be eligible for it for their CAM Group participation. IOUs may continue to use the existing PRG to conclude existing, on-going CAM procurement provided final contract selections are made within 60 days of this decision.
We adopt the PRG Participation Working Group proposal, as presented in Attachment D, to create a CAM Group for procurement for which IOUs recover costs from bundled and unbundled customers using the D.06-07-029 CAM. In order to ensure adequate representation of the various affected groups we will require that at a minimum the CAM Group should include one member representing CCAs, two members representing ESPs, and one member representing other non-bundled customers. Each IOU shall develop and convene a CAM Group when it becomes necessary according to the requirements of the adopted proposal.
Ordering Paragraph 15 of D.04-12-048 required the IOUs to consult with PRGs for all transactions greater than three calendar months. PG&E requests that PRG consultation only be required for transactions with a term greater than six calendar months.
PG&E posits that with increased market volatility, there have been times when it has been necessary to act quickly in order to mitigate sudden and significant price changes in the forward markets. Even though consulting the PRG is a relatively efficient process, there are situations where delays of even a day or two could lead to unfavorable contracting terms (costs) due to rapidly developing situations, such as unfavorable nationwide weather conditions in the winter months (November-March) and catastrophic events like Hurricane Katrina.
Moreover, greater liquidity in the markets up to 12 months forward means that there are more opportunities for PG&E to hedge these risks, provided that the short-term procurement framework is streamlined. Therefore, by changing the consultation requirements to six months, PG&E believes it will have the flexibility to respond to market conditions, and will not overload the PRG with discussions of liquidly traded, standard transactions.
PG&E argues that no party has opposed its proposal to change the required PRG consultation from the current requirement for any transaction with a delivery term greater than three months' duration to a transaction delivery term greater than six months' duration.
We deny PG&E's proposal to change the required PRG consultation from the current requirement for any transaction with a delivery term greater than three months duration to a transaction delivery term greater than six months duration. PG&E has not demonstrated that the procurement process has been detrimentally inhibited by the timeliness of the PRG process. Emergency PRG meetings have been successfully convened to address issues requiring quick action, and the appropriate process for requesting an emergency PRG meeting based on extenuating circumstances is described earlier in this subsection.
3.2. Independent Evaluator/IE Report Template
In D.04-12-048, the Commission authorized the IOUs to use an independent evaluator (IE) to monitor competitive solicitations that involved affiliate transactions, IOU-built or IOU-turnkey bidders. In D.06-07-029 and D.07-09-044, the Commission established the conditions for IE participation in the Energy Auctions. The Commission also requires that an IE be used in all RPS solicitations. Since 2004, each IOU has gained some experience with the use of the IE. While the policy surrounding the use of an IE is not within the scope of this proceeding, parties were asked to evaluate the implementation of the use of IEs. In particular, parties were asked to consider the following questions:
o Should all competitive solicitations require an IE?
o Should solicitations that do not have affiliate transactions, or involve a utility-owned or utility-turnkey bid require an IE?
o How can the Commission ensure the impartiality of the IE?
o What are the costs and benefits associated with the use of an IE, and how do these benefits directly affect procurement outcomes?
In D.04-12-148, the Commission stated that:
"IEs should come equipped with technical expertise germane to evaluating resource solicitation power products... IEs should be familiar with the various standard contracts and industry practices. IEs should have experience analyzing the relative merits of various types of PPAs. IEs should be able to evaluate PPAs, turn-keys and IOU-builds on a side-by-side basis. An IE should make periodic presentations regarding their findings to the IOU and to the PRG. The IOUs may contract directly with IEs, in consultation with their respective PRGs. The IOUs shall allow periodic oversight by the Commission's ED. Alternatively, ED can contract with IEs directly, but we will not require this given that this may result in unacceptable delays in the procurement process. IEs shall coordinate to a reasonable degree with assigned ED and staff as a check on the process.159
All three IOUs generally agree that the use of IEs in RFOs provides a significant level of oversight, fairness and assurance to the overall solicitation process.160 However, the IOUs disagree on the types of solicitations in which IEs should participate. PG&E believes that IE participation in solicitation processes where the potential for ownership interests exists is beneficial; however, the use of IEs should be optional when no ownership interest exists.161 SCE does not feel that an IE should be required for solicitations where an affiliate is not participating in the solicitation and there is no utility-owned or utility-turnkey project in the solicitation. SCE states that when no incentive exists for the IOU to deviate from "fair, consistent and reasonable practices,"162 the implementation costs of retaining an IE may far exceed the benefits. SDG&E states that while it is not necessary to mandate the use of an IE in all RFOs, SDG&E has found the IE's participation to be of value.163
PG&E states that the IOU, ED and the PRG must balance the cost and expertise that a candidate IE brings to the solicitation process with any perceived conflicts that may exist including (1) a financial interest in the IOU and (2) any consulting work that the IE may have done recently for the IOU or any potential bidder. PG&E feels that such activity should not automatically disqualify an IE from consideration; rather the IE should be required to fully disclose any such conflicts.164
To ensure impartiality of the IE, SCE suggests that "Energy Division staff and/or legal counsel review the IE engagement scope and contract terms periodically, or when a new IE is being retained by SCE in order to ensure that mutually agreeable terms are added to the IE retention, such as direct lines of communication between the Energy Division and the IE or the PRG and the IE."165 SCE goes on to state that during the selection process, the development of the scope of work, and the drafting of the contract terms with the IE, the Energy Division should be involved and have the right to final approval of such engagements.166
SDG&E suggests that the ED involvement in the PRG ensures a fair IE hiring process. Furthermore, SDG&E states that ED "staff have the ability to contact the IE at any point for an update and to review IE reports at the conclusion of an RFO."167 SDG&E rejects the suggestion that the Commission hire and retain the IE stating that this process would delay and hamper procurement efforts and the Commission and the PRG already have full access to participate in the IE process at all stages, including selection.168
PG&E states that the costs associated with the use of an IE fall into three categories: (1) the direct cost of the IE services, (2) any incremental time needed to bring the IE on board and involve the IE in the RFO process and (3) any incremental work required of the bidder to assist the IE in the scope of work.169 SCE states that the obvious cost of the IE is the consulting payments, which are borne by the IOU's bundled customers.170 All three IOUs state that there are many intangible benefits to the use of an IE including increased confidence by market participants in utility procurement practices and that selected offers were the most economical and appropriate procurement choices.
WPTF disagrees with PG&E on the matter of IEs only being retained in solicitation processes greater than five years stating that the purpose of the IE is to ensure that utilities do not engage in preferential treatment of their affiliates or their own projects. IEP, NRG, DRA, TURN and WPTF voiced concerns over the actual independence of the IE suggesting that the best way to ensure a fair and impartial process was for the Commission to hire and supervise the IE. NRG states that an "IE cannot be truly "independent" under circumstances that could result in future limited engagements if the IE is critical of utility procurement practices or proposals or fails to select the utility- or affiliate-build option..."171
TURN agrees with the IOUs that the use of an IE significantly enhances competition within the solicitation process. DRA believes that letting the IOUs hire and manage the IE raises concerns regarding his or her independence. Although in the initial phase of the IE selection the IOUs consult PRG members and Energy Division staff, once the IE is hired most of his interactions are with the IOUs. Most procurement practices are already closed to public and market participants, so the true independence of the IE brings more confidence to this process. Therefore, to ensure the true impartiality of the IE, DRA recommends that the Energy Division hire and supervise the IE, in consultation with the IOUs and the PRG.172
DRA also recommends that the Commission require the following information regarding the use of IEs in the next LTPP proceeding:
· The name and information of the IE for each IOU
· The type of procurement solicitation the IE was used for
· The amount of money involved in the procurement solicitation
· The cost of the IE for each solicitation for each IOU
As discussed in D.04-12-048, the initial IE mandate was intended as an interim approach that was to be refined based upon further experience. Based on the record in this proceeding it is reasonable to find that the IE process, while deemed beneficial by most involved, requires further refinement in order to maximize benefit to all involved parties. The Commission recognizes the need to develop a fair and transparent process for IOUs to use in selecting the IE for each RFO process. We acknowledge that ensuring the independence of the IE is of the utmost importance and that the current hiring and selection process may not adequately ensure, or at least appear to ensure, such independence. Furthermore, we feel that it is important to develop multiple qualified candidates for the IE position that are familiar with California policies and practices and our high standards for procurement.
At this time, it is not practical to transfer the IE contracting authority to the Commission; however, we will continue to explore ways in which to do so in the future. In the interim, there are several steps that can be taken to ensure the independence of the IEs while also developing a robust pool of qualified candidates. D.04-12-048 states that the IOUs may contract directly with the IE's in consultation with their respective PRGs. To strengthen this approach, we direct each IOU, in conjunction with each respective PRG, to develop a pre-qualified pool of at least three, but preferably more, IEs to be used beginning January 1, 2009.173,174 Each IOU should develop and periodically add175 to its IE pool as follows:
1. The IOU shall develop a list of prospective IEs via industry contacts, literature searches, PRG recommendations, and similar methods, solicit information from the prospective IEs and circulate the list of candidates and their "resumes" to the PRG and ED staff for feedback;176
2. The IOU should rely on the guidance regarding IE expertise and qualifications provided in D.04-12-048. However, these qualifications should represent the minimum necessary for an IE to be effective, and the IOU and the PRG should include any additional relevant information that it has gained through its experiences implementing the IE requirements;
3. The IOU and PRG shall interview a subset of prospective candidates that the IOU, its PRG, and ED staff deem most suitable for the role (IOUs should arrange for the PRG to conduct interviews with candidate IEs in isolation from the contracting IOU);
4. The PRG shall coordinate the development and submittal to the IOU its recommendations on each prospective candidate (including the general consensus and any opposition to the consensus). The IOU shall submit a written list of qualified IEs to ED to add to the IOU's pool. The list must contain the recommendations of the PRG that were submitted to the IOU. ED will evaluate the proposed IE's competencies based on the guidelines in D.04-12-048 as well as evaluating the IEs independence including any conflicts of interest.177 ED shall give final approval for inclusion of an IE in the IE pool by letter to the submitting IOU;178
5. Beyond the development of the initial IE pool, additional IE's may be added to the pool by following the same procedures listed above;179
6. An IE may remain in the IE pool for two years, after which he/she must go through a reevaluation process based upon the inclusion criteria to assure continued compliance. The reevaluation process will involve additional reviews of the IE candidate by the PRG, IOU and ED staff including additional interviews, if necessary;180 and
7. The IOUs shall develop a pro forma contract to be used each time it contracts with an IE. If deviations from the pro forma are necessary, the modifications must be fully supported by ED staff when the IOU seeks final approval of the contract. This pro forma contract shall be submitted as part of the next LTPP filing and will be subject to Commission approval.181
The Commission adopts SCE's suggestion that during the selection process, the development of the scope of work, and the drafting of the terms of the contracts with the IE, ED should be involved and have the right to final approval of such engagements. Final approval of IE pro forma contracts shall be made at the discretion of the Commission as part of the upcoming LTPP proceeding. As noted above, the IOUs will submit a list of qualified candidates to ED (including the PRG's recommendations); however, ED will make final approval of an IE for inclusion in the IE pool.182 The Commission further recognizes that IE costs as part of the procurement process are recoverable through ERRA.183
The Commission further recognizes that transparency of the IE selection process is of critical importance and therefore adopts DRA's recommendation with modifications that the name and information of the IE for each IOU, the type of procurement solicitation the IE was used for and the amount of money involved in the procurement solicitation be reported to the IOUs PRG before and after the solicitation takes place. We acknowledge that this and other information is already available to the IOUs' PRGs.
The purpose of an IE in the RFO solicitations is to ensure a fair, competitive procurement process free of real or perceived conflicts of interest. Based on the record in this proceeding it is reasonable to find that an IE should continue to be contracted with and retained for all long-term solicitations that involve affiliate transactions or utility-owned or utility-turnkey bids. Further, given that IOUs may not know with certainty whether or not it or its affiliate will bid on a particular solicitation, the Commission requires that an IE be utilized for all competitive RFOs184 that seek products of more than three months in duration.185 For solicitations of less than five years, the IE report shall be filed with the QCR.
An additional concern of market participants is that the IE remains independent and free of any and all conflict. The Commission agrees with market participants in this regard, but we realize that the IEs which are qualified to perform the functions required will most likely come from firms that have multiple clients. We are also cognizant of the fact that a consultant's client base is fluid. Given all of these factors, a potential conflict of interest may present itself over the life of the IE contract that was not present when entering into the IE contract or the IE pool- whether it is with the individual IE or the IE's firm. Therefore, we order the IOUs, in consultation with the PRG and ED, to develop comprehensive conflict of interest disclosure requirements for the IE. An IE may be disqualified from participating in an RFO process if there are particular egregious conflicts of interest that arise during the contract. The conflict of interest disclosure requirements shall be approved along with the pro forma contracts in the next LTPPs.
Currently, the IE submits a report to the Commission in support of applications for resources procured in competitive RFOs; however, the reports have been inconsistent and do not always contain the necessary information for the Commission to make an informed decision. We recognize that no formal template for IE reports has been offered; therefore inconsistencies are to be expected. In order to clarify the information required in IE reports, we direct ED to develop a template for IEs to use when developing their reports. The report template should, at a minimum, contain the following information and answer the following questions:186
1. Describe in detail the role of the IE throughout the solicitation.
2. Is the IOU's methodology for bid evaluation and selection designed fairly?
3. Was the least cost, best fit (LCBF) contract evaluation process fairly administered? (This should include a thorough analysis of the RFO results.)
4. Did the IOU do adequate outreach to bidders, and was the solicitation robust?
5. Were project-specific negotiations fair? 187
6. Does the contract merit Commission approval?
We direct ED to develop the IE report template through a public process which will allow for public comments and workshops, if needed. ED shall submit the IE report template for public comment no longer than 30 days after adoption of this decision. After receiving comments and making necessary revisions, ED shall serve the final IE Report Template on the service list. Once adopted, these IE report templates shall be included as part of the next LTPP filings.
3.3. RFO Process
Development of a functional RFO process in the hybrid market is an evolutionary exercise in which we must balance a number of competing priorities, and we are continually striving to improve on the process based on industry experiences. Aside from UOG bids, which are addressed in the following policy section, there are two primary sources of tension in the existing RFO process: the transparency of the process and the restriction of certain products from an RFO (e.g., truly all source solicitations versus new generation only restrictions).
AReM states that the sharing of capacity costs via the CAM mechanism established in D.06-07-029 for resources acquired by the utilities reinforces the need to assure that the RFO process is conducted in a fair and transparent manner.
Calpine states that the current practice of excluding existing generation (uncommitted or otherwise somehow available) from new generation RFOs minimizes the benefits of competitive solicitations and sends the wrong message to the market.
Calpine recommends that IOU RFOs be approved by the Commission before the solicitation goes public. In support of its recommendation, Calpine states that if an RFO is found to be noncompliant late in the process the whole time-consuming process must be restarted or bids from a noncompliant process may have to be accepted because there will not be enough time to meet supply needs.
IEP does not believe that the current IOU RFO process is sufficiently transparent or fair to allow for truly competitive bidding. IEP recommends the following refinements and requirements to the RFO Process:
· No potential bidder should have preferential access to any information relative to any other bidder. This may entail enforcing codes of conduct between functional groups of the IOU.
· The long-term procurement processes should (1) provide for input by the potential supplier community to help the IOU identify RFO terms that will align IOU needs and market-based providers' offers, and (2) provide for reasonable schedules and adequate clarity and communication with the potential supplier community over terms of the RFO.
· The RFO and contract terms must be fair. For instance, the imposition of differential contract terms (e.g., collateral and credit terms) between IOU and non-IOU offers must reflect the actual differences in risks and circumstances.
· The evaluation criteria and process must be fair.
· Evaluation criteria should be transparent and consistent.
WPTF argues that, although all-source solicitations are strongly encouraged by D.04-12-048, the utilities have overwhelmingly favored RFOs for new generation. Utility customers benefit when the competition to supply their needs is as broad as possible. The eligibility of all resources, which includes existing generation, repowering projects, renewable resources, as well as new generation, to bid in any utility RFO should be confirmed and implemented by Commission order.
WPTF proposes that a utility should produce clear bid evaluation criteria well before accepting competitive bids. Ambiguous criteria and inadequate lead time for bid preparation blocks independent proposals and contributes to inefficient project valuation. WPTF believes that bid evaluation criteria, including the methodology for comparing UOG against power purchase agreements, should be determined by a public process and published in detail so that all bidders know how bids will be scored and how to design a competitive bid.
TURN disagrees with the IEP/WPTF position that the entire bid evaluation methodology in an RFO, including monetary and non-monetary values, computer programs and input assumptions, should be made publicly available to bidders. TURN states that this proposal is reminiscent of the Biennial Resource Plan Update, in which the Commission attempted to specify the entire bid evaluation protocol in great detail. TURN notes that the BRPU process failed, in part because bidders were able to game the evaluation protocols. TURN's position is that bidders should be given a reasonable amount of information regarding how their bids will be evaluated, and that as long as an IE is reviewing the process there should be no meaningful opportunity for a utility to skew these factors. TURN also notes that the models and input assumptions in utility RFOs are typically "locked down" prior to any bids coming in.
TURN endorses the IEP recommendation that the codes of conduct and bans on preferential access to information that apply between a utility and a generation affiliate should extend to the internal IOU functions involved in project development and bid preparation. Under these restrictions, the employees developing the utility-build bid would be barred from access to any information not made available to outside bidders.
TURN also contends that it is generally desirable to solicit bids from as many sources as possible. However, when an IOU is seeking specific types of products (e.g., "new" generation for reliability purposes, in order to assure an adequate future PRM in its service territory) it makes sense to tailor the RFO accordingly. TURN notes that this is entirely consistent with D.04-12-048 (p. 128), in which the Commission stated that: "the IOUs have the flexibility to tailor their RFOs to reflect their specific resource needs . . ."
PG&E argues that it discusses its RFOs with ED and the PRG and holds a bidder's conference prior to launch, and solicits feedback. PG&E believes that the current consultation process has worked well and should be continued.
SCE acknowledges that RFO draft document review and comment by market participants can be useful, when time allows for such review and comment. SCE claims that in its last several RFOs it has endeavored to accommodate this type of process and will continue to do so in the future. SCE continues that, unfortunately, sometimes it is either not possible or would unduly constrict the schedule for other RFO activities (such as for response development or negotiations, etc.). Therefore, SCE does not support the recommendation that such a process be required for every RFO.
SCE is concerned that while it believes that consultation with the PRG and Commission staff is helpful, formal Commission approval of RFO documents would add a considerable administrative burden to the process with no demonstrated benefit. Under its current plan, SCE provides draft versions of its RFO documents to its PRG prior to finalization of the documents. The PRG and the ED are then given an opportunity to provide input to SCE on all RFO elements, including requirements and pro forma contracts. SCE then carefully considers this input when finalizing the RFO documents.
SCE states that it explicitly outlines its valuation methodologies and valuation inputs in its competitive solicitations via the RFO public documents. SCE argues against a more complete disclosure of all data required for valuation and selection, as this would, for example, allow bidders to determine areas where they have market power and are able to extract a greater premium for their products. SCE believes that allowing bidders to have exact formulas and software programs used by the utilities to evaluate bids would allow them to manipulate the process to drive prices higher.
SCE claims that it provides a very detailed explanation of the LCBF evaluation process in its LTPP and that there is also ample guidance provided to the bidders via the RFO Documents (i.e., Transmittal Letters, Offer Sheets, and associated Appendices), bidders conference calls, and SCE's frequently asked questions (FAQs) pertaining to any particular RFO.
SCE argues that while it procures the vast majority of its capacity and energy needs through all-source RFOs, there are times when a specific need is identified and the only efficient manner to meet this need is through a targeted RFO. SCE's New Generation Resources and Renewable RFOs are examples of solicitations tailored to meet targeted needs identified by the Commission. SCE does not believe that a requirement that prohibits the IOUs from conducting targeted solicitations would be in the best interest of IOU customers or potential bidders.
SDG&E identifies the key benefit of competitive bid solicitations as the bringing together of the largest number possible of market participants to make offers to sell, thus promoting liquidity, competition and price discovery. SDG&E cautions that these benefits must be balanced with the fact that RFOs are very slow relative to the volatility of market prices, thus leaving the portfolio exposed until contracts are negotiated and signed. Further, SDG&E notes that RFOs are administratively costly due to the extensive contract negotiations required to cover deal-specific commercial, legal and credit terms. SDG&E regularly evaluates the needs of the portfolio to determine whether RFOs present advantages compared with the alternative of spot trades, exchange traded products, bilateral transactions or some combination.
SDG&E believes that RFOs are most beneficial for long-term (not short-term) procurement where the utility is acquiring highly structured, non-standard products and little or no transparent pricing exists. RFOs are also useful where products may be standardized, but no exchange exists on which to trade them. SDG&E also notes that when multiple projects are chosen in the RFO process, it creates a tremendous amount of workload at a single point in time, whereas bilateral contracting spreads this work over a longer period of time.
Finally, SDG&E proposes to conduct renewables procurement along with conventional resources in its all-source solicitations.
Regarding tailoring RFOs to, for example, address system reliability needs (and therefore limiting the solicitation to new or repowered generation) or RA requirements (system, zonal, or local), the Commission is in full agreement with the IOUs that ratepayers benefit from this level of flexibility, and that IPPs actually benefit from this practice as well in that they are properly discouraged from utilizing their resources to develop bids for products not needed by the IOU. That being said, we expect RFO product descriptions to be based on each utility's operational needs and not create false barriers to participation or otherwise limit the competitive process.
Regarding transparency, the IPP community desires more information in the RFO process to ensure that (1) developers can put their "best foot forward" in their bids, and (2) the IOUs cannot put a thumb on the scale in the bid development and/or evaluation process in favor of UOG or affiliate bids. The IOUs argue that their practices provide sufficient information for parties to design bids to their strengths, and that providing too much information could result in gaming opportunities and consistently higher bids.
The fundamental issue the Commission must address concerning RFO transparency is what types of transparency benefit ratepayers. Generally, we concur with TURN and the IOUs that too much information can result in undesirable outcomes. However, in some instances the RFO information provided by IOUs has been sufficiently short on details (e.g., instances in which an IOU had too much latitude to identify a bid as nonconforming based on the vagueness of the bid requirements).
One of the working groups created as a result of the workshops ED held in the spring was the Transparency Working Group. The Transparency Working Group was tasked with identifying, among other things, areas in which additional information could be provided to IPPs by the IOUs that would not harm the competitive process. However, the group did not actually focus on most of the transparency issues raised by IPPs in comments and workshops, so were unable to make any recommendations as a result of this process.
The Commission believes that the RFO process would benefit from additional rigor on the part of the PRGs, IEs, and ED in scoping, reviewing, and revising RFO bid documents to help identify data gaps, confirm the fairness of the components of the RFO that the IOU identifies as confidential, and ensure that both the letter and spirit of the RFO are consistent with the Commission policies set forth in this and past procurement decisions. To address these concerns, the IOUs will need to build consultation with PRGs and ED into the early stages of the RFO process.
Prior to drafting RFO bid documents, we will require all IOUs to hold a meeting with the IE, PRG, and ED to outline their plans (quantities and types of products they intend to solicit, category definitions if multiple bid categories are envisioned, any unique circumstances to be addressed in the RFO) and solicit feedback. Then, the draft RFO bid documents are to be developed under the oversight of an IE. The bid documents should include (for internal review by the PRG and ED staff) clear descriptions of the bid criteria (including the rationale for selecting and weighting the criteria) and the evaluation and selection process. The draft bid documents are to be vetted through the PRGs, and any differences are to be resolved with ED staff in advance of the public issuance of bid documents. In addition, the IOU is to provide the PRGs and ED staff a decision rationale with respect to each selected and rejected bid upon completion of an RFO.
Finally, no IOU is to initiate an RFO for new fossil resources that have not been formally authorized in an LTPP decision unless the IOU makes a strong showing in advance, by an approved Advice Letter, that unusual or extreme circumstances warrant such an action.
The Commission has also been unsatisfied with the amount of process details provided by the IOUs in their applications for Commission approval of winning bid projects. Substantial inadequacies in initial submittals have required ED staff to issue data requests to develop an adequate record. To remedy this concern, we direct ED to develop a template for IOUs to use when developing their applications. The selected project application template should, at a minimum, cover the following topics:188
1. Detailed description of bid selection process,
2. Consistency with Commission decisions,
3. Consistency with the EAP loading order and the IOU's GHG reduction strategy,
4. Outside participation and feedback, and
5. Contingencies and milestones.
We direct ED to develop the selected project application template through a public process that allows for public comments and workshops, if needed. ED shall submit the project application template for public comment no longer than 30 days after adoption of this decision. After receiving comment and making necessary revisions, ED shall serve the final project application template on the service list. Once adopted, the template shall be utilized by the IOUs in future project applications.
One aspect of the RFO bid selection process that troubles this Commission is the protracted RFO process itself, from conducting an RFO, negotiating contracts, and ultimately filing applications with the Commission for approval. PG&E released its LTRFO on March 18, 2005, and filed the winning contracts for Commission approval a full 13 months later on April 11, 2006 (seeking expedited approval). SCE was authorized to conduct a solicitation for up to 1,500 MWs on July 20, 2006, released its RFO on August 14, 2006, executed contracts on February 15, 2007, and filed for approval of the contracts on February 28, 2007. SCE also has a standard track from this solicitation that is due to close in the first quarter of 2008 - nearly 18 months after releasing the solicitation. This process is much too time intensive; much too protracted. The process, as the IOUs are currently implementing it, invariably places our IOUs behind the market - in a reactive, catch up position (and all-too-often trying to do so via expedited public review). This is not in the best interest of California's ratepayers.
Similarly, IOU All Source RFOs consistently extend from early in the summer into the fall, and often completed very close to the year-ahead RA filing dates, essentially freezing out other ESPs from the market.
We realize that this is a fairly new method of procuring resources but clearly improvements must be made - and quickly for that matter. Several steps to improve the procurement process have already been taken with the issuance of this decision today, but we are not convinced that more improvements are beyond reach, and we direct the IOUs to work with the PRGs and ED staff to develop ways in which efficiencies can be achieved in the RFO process.
Conclusion of Law (COL) # 22 in D.04-12-048 states that "Allowing an IOU to meet its RPS annual procurement target via an all source RFO, as well as via an RPS-specific solicitation, is consistent with the Legislature's clear intent that renewable procurement be integrated as closely as possible with general IOU procurement practices." We encourage SDG&E and all the IOUs to encourage renewable resource bids in their RFOs, with the two following caveats intended to ensure that the renewable procurement processes developed in the RPS proceeding (MPR, etc.) are not circumvented via the all source RFOs:
· All resources within an RFO should be compared against one another on a consistent, LCBF basis using the GHG adder to increase the costs of fossil resources relative to renewables (i.e., the solicitations should not be designed with separate groupings for renewables and conventional generation), and
· Decisions regarding whether or not to continue conducting separate RPS solicitations should be addressed in the RPS proceeding.
3.4. Contract and Bid Evaluation
As the Scoping Memo specified, a key goal of this proceeding is to review the procurement process of the RFOs to consider whether any refinements are necessary to further the goal of open, transparent and competitive procurements. An open, transparent and competitive procurement process is the king-pin to a successful hybrid market, and that theme, in tangent with environmental issues, guide our decision on the 2006 LTPPs. Therefore, although we address specific procurement related issues in this section of the decision, our commitment to an improved procurement process promoting a hybrid market speaks throughout the decision.
The three IOUs report that LCBF is their guiding principal for contract/bid evaluation. As SDG&E states, "[I]t is not feasible, however, to adopt a pre-determined, `one size fits all' set of evaluation criteria . . ."189 SDG&E includes the evaluation criteria it plans to use in each RFO.
SCE's Least Cost valuation takes into account credit, collateral, DE, GHG adders and transmission adders, as well as improvements in energy and ancillary service valuations, with the ability to value offers under different pricing scenarios to generate a net present value (NPV) for each contract. SCE achieves a Best Fit by determining by a mathematical equation how to maximize the NPV with capacity and energy needs, as well as with qualitative characteristics such as location, product type, procurement limits and other criteria.190 While SCE believes that the RFO process should be as open as possible, it still urges the Commission to protect SCE's [and by extension the other IOUs] confidential and proprietary assumptions, models, formulas and computer programs used to select resources in an RFO from market participants to prevent the manipulation of bids. SCE also argues against the adoption of a particular model, such as Black's Model as requested by Aglet, for all IOUs to use for all transactions and to allow each IOU to develop and implement its own evaluation system.191
PG&E presented a detailed list of the evaluation criteria it uses in the RFO process during the May workshops, including GHG adders and DE. For long-term RFOs, PG&E delegates to the IE and his/her staff the task of developing and implementing criteria to ensure that PG&E is selecting the best bids in the process.192
The evaluation criteria used in competitive solicitations must be clear, transparent, and available to potential bidders early enough in the procurement process to permit potential bidders to tailor their projects to fit the utility's actual needs. Bid evaluation is currently one of the most opaque steps of the procurement process, and as a result not only do "losing" bidders not know why they lost, but "winning" bidders may similarly not know why they won.
A well-functioning competitive process requires that all bids - including the bids of utility-sponsored projects - are evaluated using criteria that are consistent with the goals of the RFO and in a manner that encourages competition among bidders to meet the objectives of the RFO. When the utility functions as both buyer and seller, it is particularly critical to ensure that the bid evaluation is fair and transparent. In the absence of a fair and transparent evaluation process, it is unlikely that ratepayers will benefit fully either from competition or from the utilities' participation in a hybrid market.
We have taken many steps in an attempt to make the procurement process more transparent and fair. We discuss below certain bid evaluation metrics that we urge the utilities, in conjunction with Independent Evaluators, Procurement Review Groups and Energy Division, to consider when developing the RFO bid documents and process. In addition, when filing an application for approval of a resource selected through a competitive solicitation, a utility must justify why the bid evaluation criteria were appropriate.193
In general, we are concerned that the IOUs are not properly taking into account certain bid characteristics that in hindsight could be very costly. We realize that `hindsight is 20/20,' but we are convinced that the IOUs need to be much more selective when it comes to the ultimate winner of an RFO. We agree with the IOUs that it may prove counterproductive to be too prescriptive in identifying specific RFO bid evaluation criteria. A `one-size-fits-all' approach may not be achievable and, therefore, may not truly `fit all.' However, we are concerned that the other extreme - allowing IOUs too much leeway in determining the criteria upon which a bid will be evaluated - is also problematic.
We understand that the LCBF framework cannot entirely be reduced to mathematical models and rules that completely eliminate the use of qualitative factors. However, the IOU must be able to fully justify why a particular project wins a solicitation, and we provide here some general guidance to the IOUs regarding the types of evaluation criteria that should be applied to bids in RFOs for the resources authorized in this decision.194
The bid criteria raised specifically by parties in testimony, including credit and collateral, debt equivalence, Fin(46), and transmission costs/savings, are discussed in further detail in the following subsections. Other obvious criteria include capacity and energy benefits, resource diversity, portfolio fit, local reliability/resource adequacy, and congestion costs. Some criteria for which we believe the IOUs need to provide greater weight include disproportionate resource sitings in low income and minority communities, and environmental impacts/benefits (including Greenfield vs. Brownfield development).
Finally, one criterion that we believe requires far greater scrutiny by the IOUs is project viability. PG&E executed contracts for seven new resources as a result of its 2004 LTRFO - Starwood, Panoche, Eastshore, Humbolt Bay Replacement, Russell City, Colusa, and Bullard. These resources represent 2,250 MWs of new generation in PG&E's service area. However, at the time PG&E executed contracts for these resources, only one resource - Russell City - had obtained a permit to construct from the CEC. These contracts were approved by the Commission in D.06-11-048. In a notice submitted to the service list in this proceeding on November 13, 2007, PG&E represented that only two projects had obtained permitting - Starwood and Russell City195 - and not a single project had begun construction.
In addition, on November 14, 2007, PG&E filed an application for expedited issuance of a certificate of public convenience and necessity for the Colusa power project. In the application, PG&E states that E&L Westcoast Holdings, LLC (the entity that won a PSA contract in the 2004 LTRFO) informed PG&E that it intended to terminate the existing PSA, and offered to sell and transfer the development assets associated with the proposed project to PG&E. Due to the existing need in PG&E's service territory and the short time between the application and the proposed online date of the plant, PG&E proposes to construct the Project itself.
We note that PG&E is not the only IOU that has demonstrated difficulty getting approved procurement permitted, constructed, and operational. SCE is currently experiencing significant delays in bringing two resources from its fast track RFO to fruition. In SCE's fast track RFO it selected offers from Blythe Energy, LLC (Blythe) and CPV Ocotillo, LLC (CPV) which resulted in 490 MW and 455 MW, respectively, of incremental generation capacity. SCE filed an application for approval of these projects on Febraury 28, 2007. These projects have yet to be approved by the Commission due to significant project development uncertainties presented as a result of the ACCs rejection of the DPV2 project.
All this is occurring despite the fact that there are 6,000 - 8,000 MWs of permitted projects in the state of California. However, projects that have already obtained permits from the CEC are consistently not winning projects in the utility RFOs. We recognize that the primary driver of this result is cost, but we are concerned with the hidden viability costs associated with projects that experience extensive delays or do not come to fruition.
If procurement authority approved in the 2004 Long-Term Procurement Proceeding decision has yet to reach the construction phase - or to even be permitted in many instances - then the IOUs must be more proactive in determining project viability among the offers submitted into RFOs.
One way that the IOUs could reduce project development uncertainty is to recognize as a bid evaluation criterion a value for projects that have already gone through the CEC's permitting process (potentially including various sub-criteria for project development efforts/developer progress to date, local permitting status, and project viability vs. cost196) and an incrementally higher viability value for "new" resources that already exist (i.e., repowers) or have begun construction. While this will not remove all development uncertainty associated with a particular project, it will remove significant uncertainty, quite likely speed up the process, and reduce hidden and indirect viability costs associated with delayed or aborted projects.
Each IOUs' LTPP includes details of their respective credit and collateral (C&C) policies for different types of procurement for their portfolio needs. The Scoping Memo asked the IOUs to consider three questions that in summary asked whether it was possible, and practical to have standard C&C policies across all three IOUs and whether there was an alternative method, other than C&C, that could be utilized.
Like a number of other issues under consideration in this decision, C&C policies are a multi-faceted topic. To begin, C&C can apply to both parties to a PPA. Any benefit an IOU receives from having a counterparty post collateral may be offset by the fact that the IOU could be asked by the counterparty to post collateral. In addition, market conditions are volatile and even if one party is financially sound today, the counterparty may request the maintaining of collateral facilities as insurance should that sound position shift. Therefore, the C&C cost arises in the context of PPAs, and not with utility-owned assets and should be recognized as part of the contract price. Each IOU has to determine an appropriate methodology to weigh that cost as an adder in evaluating that bid.
Intervenors with an interest in a competitive, robust market are concerned that the IOUs could use C&C adders to discriminate against certain bidders in a RFO. This concern is heightened if a UOG project is competing head-to-head with a merchant-owned project, and the fear is the C&C adder, especially when combined with a DE adder, could tip the scales making the UOG project look more economic. When an asset is utility owned, the utility neither receives nor posts collateral, nor needs to maintain collateral facilities. However, on the other hand, C&C is a real cost for an IOU as it evaluates the credit worthiness of a counterparty and determines to what extent that factor impacts the bid evaluation for that asset.
While this is a strong argument in favor of standardizing the C&C factor, we have to balance that concern against the fact that if a counterparty fails economically, the IOU will have to replace the power from the market, at a higher cost to customers. The IOU needs the flexibility to weigh the financial strength of a bidder in evaluating the whole bid package.
We agree with the IOUs that crafting, adopting and implementing standard C&C rules would be difficult to do. Each bidder in a RFO has its own unique credit situation, and an IOU's own credit rating is constantly changing, which impacts the resources a bidding counterparty needs to provide on its side of the equation. After reviewing the C&C requirements used by the IOUs, and utilizing the audit results from an audit ordered by the Commission,197 we determine that no changes are warranted, at this time, on the subject of C&C, beyond approving SCE's request to increase its collateral exposure limit from $1.4 billion to $2.0 billion resulting from increased physical and financial transactions. However, as stated in the following subsection on risk management, we anticipate taking a comprehensive look at IOU risk management practices in the 2008 LTPP proceeding. Part of risk management/mitigation is credit and collateral and methods of dealing with certain types of exposure - financial risk, physical concentration, counterparty concentration, netting etc. - and we need to gather more information on these important subjects.
The issue of Debt Equivalence (DE)198 was a hotly litigated topic in the 2004 LTPP, and D.04-12-048 recognized DE as a factor to be considered by an IOU in evaluating a PPA against other contract options. That decision found DE associated with an IOU carrying a PPA on its books to be a real economic cost that can impact a utility's credit rating and cost of borrowing. Because of these factors, D.04-12-048 found that DE is properly a cost to be recovered in an IOU's cost of capital proceeding andthat, an IOU could impute a DE of 20% to a PPA as a bid evaluation tool. However, the Commission also indicated in D.04-12-048 that the adopted approach was not fixed and immutable:
DE is a subjective factor based on the credit rating agencies' perceived risk associated with PPAs. The credit rating agencies' views on such risk are not static and can change with respect to a particular PPA during the term of the PPA. In addition the imputed DE costs for existing PPAs will be reduced as the regulatory climate in California improves.199
The Commission went on to conclude that, "(a)s the rating agencies' views on DE change or as we gain more experience with DE evaluation in the [cost of capital] proceedings, we may adjust the DE methodology used in [the] future."200 The current proceeding provides a timely opportunity to reexamine the use of DE in the evaluation of bids.
Both SCE and PG&E note the economic reality of DE as applicable to a PPA, and ask that the Commission carry forward the 20% from D.04-12-048.
Two intervenors, IEP and WPTF, asked that DE be eliminated as a bid evaluation criterion considered in RFOs since it could have a negative impact on a PPA bid, especially if compared to an IOU owned asset with no imputed DE factor. On the other hand, SDG&E asks that the DE be increased to incorporate an updated methodology from S&P. SDG&E included supporting data in its testimony to justify its request to increase the DE percentage and to get an adjustment to its cost of debt and cost of equity. In response to a Motion to Strike brought by DRA, the ALJ ruled that the LTPP proceeding was not the appropriate place to argue adjustments to SDG&E or any other IOUs' capital structure.
DE has engendered considerable controversy in this proceeding. In D.04-12-048, we determined that DE is a real economic cost borne by an IOU when it enters into a PPA, and can have an impact on a utility's credit rating and ultimately increase its cost of borrowing, and that an IOU may impute a DE of 20% to a PPA bid in RFO bid evaluations. IEP and WPTF have contended in this proceeding that this determination was in error, and that the proper place to consider impacts of DE is in the IOU cost of capital proceedings and not on an individual, case-by-case basis in the bid evaluation stage of utility solicitations.
The Commission currently considers debt equivalence in two contexts. First, debt equivalence is one of several considerations that rating agencies factor into their assessment of a utility's overall risk profile. The Commission considers the rating agencies' credit ratings in the cost of capital proceeding and thus considers debt equivalence when it determines the IOUs' cost of capital. For example, in the current cost of capital applications [A.07-05-003 (SCE), A.07-05-007 (SDG&E), A.07-05-008 (PG&E)] the IOUs cite DE among a host of other factors that affect their credit risk, including loss of load due to direct access, community choice aggregation, and municipalization, high levels of capital spending and construction, high retail rates, and fuel price volatility, among others.
The second context is the use of DE in evaluating offers in competitive solicitations. In D.04-12-048, the Commission concurred with the utilities' proposal to base the debt equivalence adder on S&P's approach, "because it is the most developed and transparent approach to calculating DE."201 The Commission modified the S&P approach, however, because the 30% risk factor that S&P then applied was "too high to be reasonable and fair to all PPAs," and the Commission did not want "to create an unfair burden on or a disadvantage for independent power sources over utility-owned . . . ."202 For those reasons, the Commission elected to discount S&P's risk factor by one-third from 30% to 20% for purposes of evaluating bids in competitive solicitations.
Based on the record of this proceeding, we agree that DE in and of itself is not a cost that the utilities directly incur by entering into a PPA. DE, which is also referred to as imputed debt, is a term rating agencies use to describe the potential financial risks a utility may incur when it enters into a long-term PPA. Under certain specific circumstances, a rating agency may treat some portion of the utility's obligation under the PPA as equivalent to debt, rather than an operating cost, and may adjust the utility's credit metrics and financial ratios to reflect increased levels of debt.
When the Commission considered this issue in the last procurement proceeding [R.04-04-003], it authorized the utilities to "take into account the impact of DE when evaluating individual bids . . ." and directed the utilities to use a 20% "risk factor" for all PPAs, based on a discount of the 30% risk factor developed by Standard and Poor's (S&P) for the California utilities.203 The Commission also acknowledged, however, "As the rating agencies' views on DE change or as we gain more experience with DE evaluation in the [cost of capital] proceedings, we may adjust the DE methodology used in [the] future."204 Since the issuance of D.04-12-048, the Commission has gained more experience with debt equivalence.
The preceding discussion demonstrates that the Commission's approach to debt equivalence creates a disparity between the treatment of PPAs and utility-owned projects in the procurement process, in direct contradiction to the Commission's stated goal of promoting head-to-head competition between PPAs and utility-owned options. The evaluation of bids by PPAs in competitive solicitations includes a DE "bid adder" in an attempt to quantify potential risks presented by IPP projects, while the evaluation of utility-owned projects includes no similar upfront bid adder, even though utility-owned projects present incremental risks to ratepayers and utility shareholders. We believe that to further encourage fair, head-to-head competition between PPAs and utility-owned projects, as stated in D.04-12-048 and numerous times throughout this decision, the bid adder for PPAs should be eliminated. Based on an examination of all three of the rating agencies' treatment of DE, recent changes to these treatments, and the improved credit ratings of the California utilities, we find that no DE adder is warranted.205
We recognize that at some point, DE may reach a point where it can affect the utilities' credit ratings and cost of capital, and it is not disputed in this proceeding that the potential effect of DE on credit ratings, if any, is an appropriate topic for the utilities' cost of capital proceedings. Today's decision focuses on the evaluation of PPA bids received in utility request for offers and in no way presupposes any related cost recovery, or adjustments to capital structures in future cost of capital proceedings. We continue to direct the IOUs, especially SDG&E, to raise any individual concerns it has with the impact of a particular PPA on its debt to equity ratio in its Cost of Capital proceeding.
SDG&E is the only IOU requesting consideration for FIN 46(R)206 impacts to be considered in the bid evaluation process. While SDG&E states that it considers "PPAs to be an attractive option that mitigates construction and cost escalation risks associated with building and operating a new facility,"207 it also asks the Commission for clear guidance on how to calculate the costs for both DE and FIN 46(R) when evaluating bids. We have given guidance on DE, and now address FIN 46(R).
From SDG&E's analysis of FIN 46(R), it is possible that certain long-term PPAs are within the scope of the FIN 46(R) financial reporting requirements that would require SDG&E, as the purchaser/beneficiary of a power contract, to consolidate the financial statements of the power plant owner/provider, with its own when filing annual and quarterly reports with the Securities and Exchange Commission (SEC). SDG&E posits that this could then negatively impact its balance sheet. Therefore, SDG&E would like a mechanism to assess the potential impact of a FIN 46(R) filing requirement when it is evaluating bids.
Our response to SDG&E's request for FIN 46(R) impact treatment is that it is reasonable for SDG&E, or any of the other IOUs, to argue in its respective Cost of Capital proceeding, that it needs to increase its equity to debt ratios in order to keep its capital structure in line with Commission directives. At this point in time, without prejudice to the issue being re-introduced in future LTPP filings, we do not find that there is sufficient information for us to know how a utility should weigh the FIN 46(R) impacts of a PPA when evaluating competing bids.
SDG&E, PG&E, and SCE all stated that transmission is one of many factors taken into account as an evaluation criterion in the contract and bid evaluation process. The transmission analysis is complicated in the RFO process by FERC Order 2004, which restricts the flow of non-public information between the transmission department and the procurement departments at the IOUs.
There are also transparency issues associated with the transmission criterion, as evidenced by the fact that the Transparency Working Group addressed this subject at its September 13, 2007 meeting.208 In general, the Working Group addressed transmission related costs/benefits as they relate to: (1) particular projects under consideration in a competitive solicitation; (2) costs/benefits that may not currently be captured in the analysis; and (3) the feasibility and means by which additional costs/benefits could be captured.
PG&E and SCE209 made presentations on the means they utilize to estimate the network upgrade costs associated with a particular project. Although they each use different means to identify transmission related costs, there were no costs that were not captured. The more difficult analysis is how to evaluate the transmission benefits. For example, SCE and PG&E stated that they do not quantify the benefits associated with deferred or avoided transmission that can result from local generation. The Working Group stated in its Updated Report that a better understanding of the capacity and energy values associated with congestion are needed to more thoroughly evaluate RFO alternatives. Mirant also suggested that once locational marginal pricing (LMP) is implemented the value of local generation will be known through market prices. Without information on congestion and LMP, the parties could not reach a consensus and did not present a recommendation to the Commission.
In summary, the AB 1576 Repowering Working Group raised the transmission benefits issue in that Working Group as to how transmission costs/benefits are evaluated in the RFO process and because of interrelated issues it was also raised in the Transparency Working Group. Although participating parties have a better understanding of the challenges that are associated with assessing the transmission benefits of a particular project, they also comprehend that the problem cannot be resolved in the current market structure where locational prices are lacking. Since there are no recommendations presented for consideration, and in the absence of a fully developed record on the topic we do not make any findings or orders at this time on how transmission costs and benefits are to be evaluated for specific generation projects in the RFO process. However, as we note below, MRTU is currently scheduled to "go live" in spring 2008. As more details surrounding the implementation of MRTU become known we anticipate having more information available to make informed decisions regarding the potential impacts that this new market design may have upon IOU procurement activities. As such, we fully expect to continually examine MRTU as part of future LTPP proceedings.
3.5. Risk Management and Fuel Supply Plans
Because other market participants could use information regarding the IOUs' risk management approaches to game their bidding strategies, the IOUs consider portions of this information to be confidential. PG&E redacts virtually all of its risk management testimony, while SCE and SDG&E provide much of the programmatic details of their methodologies and redact primarily the proposed values. Due to the confidential nature of this testimony, there was little intervenor testimony in response to it (Aglet was the only intervenor that provided significant analysis of risk-related issues).
The risk management strategy SDG&E describes in its plan is generally consistent with its current practices, and is adopted as presented. However, both PG&E and SCE propose significant changes to their gas and electricity product risk management approaches. While we agree in principle with a number of PG&E and SCE's proposed changes, more work is needed before we can adopt them.
We recommend that ED, in concert with the PRG, address the issues of concern with the respective IOUs in future PRG meetings with each IOU, and that the IOUs submit revised risk management proposals via Advice Letter. In the interim, we require the two IOUs to continue operating under their existing Commission-approved risk management plans.
D.04-12-048 states that procurement contracts210 with durations of less than five years do not require Commission preapproval. Current guidance ED has provided to IOUs states that the five-year duration clock begins:
· At the time the contracted resources begin delivery if delivery begins within one year of contract execution; or
· At the time of contract execution if delivery does not begin within one year of contract execution.
There were two purposes for this interpretation. First, it prevented `contract stringing,' in which two successive contracts for the same resource, each under five years in length, could be entered into to avoid filing an application.
Second, it preserved Commission oversight and approval of procurement for the "out-years" of the 10-year LTPP planning horizon (i.e., years six through ten). ED believes that more active procurement oversight than after-the-fact quarterly compliance filings is necessary in those out years to ensure that IOU procurement practices do not result in (1) entering contracts to reduce price risk at levels that are not economically efficient (over-hedging); (2) buying excessive fossil resources that crowd out procurement of EAP loading order resources later in the procurement cycle or provide guaranteed future income streams to resources that the Commission deems incongruent with GHG goals or other policy objectives; and/or (3) buying resources that may not be needed for future load because of load forecast error or load migration to direct access or CCAs.
The IOUs are forecasting a significant shortage in contracted energy in the current LTPP cycle's out years (i.e., 2012-2016) due to the expiration of many of the DWR contracts. In light of this situation, the Commission has reviewed its current guidance to determine if there are other methods of achieving the goals which drove the development of this guidance that would provide IOUs with more flexibility in procuring for their net short positions. We adopt the following revisions:
· IOU may execute a contract of under five years without pre-approval for which deliveries end at any point within the 10-year LTPP procurement cycle, provided the procurement complies with a procurement limit methodology (which various parties refer to as a ratable rate, laddering, or layering methodology) developed by the IOU and approved by a Commission resolution or decision.
· Absent a Commission-approved procurement limit methodology, an IOU may execute a contract of under five years without pre-approval provided, per existing ED guidance, that the five-year duration clock begins:
o At the time the contracted resources begin delivery if delivery begins within one year of contract execution; or
o At the time of contract execution if delivery does not begin within one year of contract execution.
· In calculating contract duration, calendar days are used, not days of obligation, days of service under the contract, or days of need for the resource.
The Scoping Memo solicited input regarding whether all the IOUs should conform to a common set of gas hedging best practices. All three IOUs objected to this idea, citing concerns about divulging confidential information (which would weaken their negotiating positions), the lack of uniformity of their respective portfolios (hence one size does not fit all), and possible accusations of collusion.
The Scoping Memo also solicited input regarding whether all the IOUs were hedging the same relative percentages of their portfolios across the same time horizon, and if not, whether they should be. The answers from all three IOUs were no and no. The reasons cited are much the same as those addressing the question of best practices.
Aglet proposes that each IOU use the following mix as a hedging guideline - 75% swaps and 25% options. The IOUs uniformly opposed the recommendation, citing its lack of analytical support, its rigidity, and the disadvantage that such a constraint would place on the IOUs when they are negotiating these hedge products.
We will not require the IOUs to adhere to a common set of "best practices," establish identical forward positions over time according to a set formula, or achieve a particular mix of swaps and options. In addition, the IOUs and Aglet oppose the use of standardized models for calculating the To Expiration Value at Risk (TEVaR). We concur, noting the benefits of allowing the IOUs flexibility and the lack of benefit from forcing uniformity on this matter.
The Commission developed its procedures to monitor and manage rate level risk primarily in three decisions, D.02-10-062, D.02-12-074, and D.03-12-062. These procedures make use of two metrics, the Customer Risk Tolerance (CRT) and the To Expiration Value at Risk (TEVaR). The TEVaR represents an estimate, at a given confidence level, of the amount of electric rate increase that could occur due to changes in market conditions such as nuclear outage risk, hydro-power availability risk, electricity spot market price volatility, credit risk, and gas price volatility (which represents the single greatest historical source of price volatility). For example, TEVaR 95% measures the maximum rate increase over the expected value with 95% confidence level (in other words, it is the 1-in-20 worst case scenario). Likewise, TEVaR 99% is the 1-in-100 worst case scenario.211 CRT essentially is a cap on unforeseen electric rate increases looking 12 months into the future due to electric procurement activity. This was set by the Commission at one cent per kWh.212
Hedging, and particularly hedging future gas purchases, is the IOUs' primary method for reducing volatility risk, by either locking in or limiting the amount of variation of a future price. The "downside" of hedging is that it not only reduces the possibility of paying higher future prices than expected, it also restricts (directly or indirectly, depending on the extent to which options are used) the possibility of outcomes below expected future prices (which would result in lower than expected rates).
CRT and TEVaR can be expressed either as cents per kWh (that is, the average electric rate fluctuation), or dollars per year (the total portfolio cost fluctuation). The portfolio value is obtained by multiplying the rate value times the amount of kWh sales over a 12-month period for that utility. The two values interact with each other in the following manner:
· At any point in time, each IOU can calculate its estimated electricity costs (absent any hedging practices) for the following 12 months, based on current expectations of forward gas and energy prices, forecasted energy consumption, and a host of other expected outcomes.
· For any expected 12-month electricity cost, there is a value greater than the expected cost that would result in an increase in rates of 1.25 cents/kWh more than the expected rates, which would trigger a PRG meeting and possible remedial action.
· The IOU can vary the expected input values across a range of possible outcomes (based on historical variations, for instance) and create a distribution of possible electricity costs for the 12-month period (and the corresponding likelihood that each will be the actual cost after the 12 months are over), creating a distribution curve of possible actual outcomes around the expected cost.
· With a 99% TEVaR, if 99% of the potential outcomes correspond to a 12-month electricity cost that is less than the value that would result in a 1.25 cent/kWh increase in expected electricity rates, then no additional hedging would be warranted. Otherwise, additional hedging would be required to narrow the potential range of outcomes until 99% of them are within the cost resulting in the 1.25 cent/kWh increase over expected rates.
The Commission requires the utilities to submit to Energy Division monthly reports on TEVaR 99% on a rolling 12-month basis.213 These monthly reports also report the TEVaR 99% on a quarterly basis for months 13-24 looking forward, and on an annual basis for months 25-60. In the event that the 12-month TEVaR 99% value exceeds 125% of the CRT (i.e., if it exceeds 1.25 cents/kWh) then the utility calls a special meeting of its PRG to review the causes for the high volatility and decide whether new hedges are needed to bring TEVaR back within the allowed threshold.
In their descriptions of how they calculated TEVaR and made use of it, we find that PG&E's and SCE's descriptions conform to the Commission's directives to use a rolling 12-month TEVaR and compare that on a monthly basis to the CRT for purposes of determining whether to convene a meeting of the PRG and develop further hedges to bring the level of possible price volatility back inside the CRT threshold.
SDG&E, on the other hand, states that while it calculates TEVaR on a rolling 12-month basis, it instead uses a calendar year approach when it comes time to make hedging decisions (SDG&E Vol. 1, pp. 125-126). We order SDG&E to modify their methodology to comply with the rolling 12-month approach.
PG&E argues that no changes should be made to either the CRT or the TEVaR at this time. PG&E argues that this should wait until the Energy Division has conducted a thorough review of the experiences which the PRGs and the utilities have had with the existing methodology and has conducted the review of consumer risk preferences which was ordered previously by the Commission (D.02-10-062 directed Energy Division to retain a consultant to gather additional information about customer risk preferences, but this study has not yet been conducted). Thus PG&E argues against switching from TEVaR 99% to TEVaR 95% at this time.
SCE, on the other hand, argues for switching now from TEVaR 99% to TEVaR 95%, since the latter is a more robust and statistically valid number. SCE also points out that the 99% confidence level is more cautious than even reliability parameters that the Commission has set for the utilities, and asks why this should be so. SCE also notes that when they were originally established, the CRT and TEVaR values were not supported by any empirical basis. SCE argues that CRT should be indexed to inflation.
SDG&E expresses its preference for TEVaR 95% over TEVaR 99%, since the former is inherently a more knowable, predictable number, while one-in-a-hundred year events are so unusual that predicting them is impossible, and numbers that purport to do so are meaningless. SDG&E also points out that the existing value for CRT was established in D.02-12-074, when the Commission was thinking about using TEVaR 95%. The switch to TEVaR 99% came only later in D.03-12-062, and so no change to CRT is needed.
Aglet argues for changing from TEVaR 99% to TEVaR 95%, arguing that a one-in-100 level of caution is more appropriate for a "mission critical" application, where error can lead to loss of life. Aglet argues that since CRT is inherently a judgment call, not based on academic literature or empirical analysis, it is not useful to litigate or argue what level it should be. Aglet believes it should stay at its current level for now.
DRA cautions against changing from TEVaR 99% to TEVaR 95%, noting that in order to maintain the same level of protection from risk the CRT threshold should commensurately be reduced. DRA argues that SCE's proposal to index CRT to inflation is counterproductive, noting that it is especially in volatile times, when inflation is high, that consumers will want extra price security and so will desire a smaller CRT.
We agree with parties who recommend the use of TEVaR 95% as a more robust metric for risk than TEVaR 99%, and we adopt it as the primary metric for guiding hedging decisions. We will not at this time change the CRT level or the 125% threshold metric. We recognize that effectively we are loosening the risk guidelines (that is, allowing more potential for electric rate deviation). We anticipate that the effect of this change will be fairly modest, and that it will result in hedging strategies that are more robust and grounded in reality.
The Commission currently requires that the utilities report TEVaR looking forward up to five years. We believe this can be useful and so we maintain this requirement. SDG&E is skeptical of the value of TEVaR for periods beyond one year, given the amount of uncertainty that far in the future. We do not have sufficient evidence to evaluate this assertion, but we note that in any event using TEVaR for periods greater than one year is not the main metric used for guiding hedging decisions.
The parties also describe other risk metrics which they believe will be useful - such as forward-start TEVaR and one- and ten-day VaR. We welcome the use of these metrics in evaluating risk, but note that these are not the metrics guiding hedging decisions. The rolling 12-month TEVaR 95%, compared against 125% of CRT, will perform that function.
In addition, in the 2008 LTPP proceeding, or in another subsequent proceeding (see Fuel Supply Plans section), ED may convene a workshop to discuss possible modifications to risk management policies, including topics such as CRT levels, TEVaR, other risk metrics, the use of the Black Model, and a study of customer risk preferences.
Each IOU has a gas fuel portfolio for its DWR gas-tolling contracts and a gas fuel portfolio for resources that it owns or contracts with directly via PPA and QF contracts. The Scoping Memo solicited input regarding whether modifications were necessary to make hedging more consistent. All three IOUs indicate that their approaches for both portfolios are the same, although because of differences in the power plants those portfolios serve, the mix of hedging instruments may differ. Currently, the DWR supply and hedge plans are updated twice a year, while the non-DWR hedge plans are updated less frequently, when requested by the Commission.
SCE proposes to coordinate the scheduling of its ratable rate update for its own portfolio and its DWR portfolio. SCE requests that both portfolios be updated annually, at the time of the ERRA filings. No party has objected, and we agree that this approach would streamline administrative efforts, and so we will order SCE to update its ratable rate schedule for its own portfolio annually at the same time as the ERRA filings.
We also authorize the IOUs to update their gas supply and hedge plans for their DWR portfolios (for SCE, this includes its ratable rate schedule) annually, instead of twice a year. But because DWR has not participated in this proceeding or agreed to this change, we cannot enforce the change for the IOUs' DWR portfolios at this time. If and when DWR agrees to this change, the IOUs should notify the Commission by Advice Letter.
The nuclear and coal fuel plans proposed by the IOUs are adopted as presented. The gas supply procurement proposals of the IOUs in their 2006 LTPPs are not adopted because the Commission needs to address and review the proposals by the IOUs more thoroughly than we have in this current proceeding, and assess the proposals in conjunction with other rulemaking proceedings. For example, since the date the IOUs submitted their gas supply plans, the Commission initiated a rulemaking which will address the IOUs procurement of natural gas supplies from LNG regasification terminals, R.07-11-001. In addition, the Commission will address other gas supply procurement issues involving the IOUs, including gas supply, firm interstate pipeline capacity, and storage in a subsequent proceeding.
In order for the IOUs to continue necessary gas supply procurement for their electric generation requirements, the Commission authorizes the IOUs to continue operation under their existing gas supply plans approved in the 2004 LTPP and 2005 Short-Term Procurement Plans until new gas supply plans are approved by the Commission. If an IOU needs to propose specific gas supply procurement contract(s) that are not authorized by their existing gas supply plans beforehand, an IOU can file an application with the Commission to receive such authorization.
3.6. Streamlining and Transparency of Compliance Filings
Attachment A to the Scoping Memo directed the IOU's to "...describe the process for the Commission's review of the implementation of the Procurement Plan."214 The Scoping Memo also detailed the numerous filings that are currently required of the IOU's to demonstrate compliance with the Commission-approved AB 57 LTPP and stated that the IOUs should explain the procurement information reported to the Commission in the following reports:
· Monthly Reports
o Portfolio Risk Reduction Report
o Monthly ERRA Report
o Standing Data Requests from Energy Division or other parties
· Quarterly Filings
o Quarterly Compliance filings
· Semi/Annual filings
o ERRA filings
· Biennial filings
o Biennial Long-Term Procurement Plan
· As Needed Filings
o Non-Conforming transactions
o Advice Letter updates to LTPP
The Scoping Memo also stated that "the IOU should describe the process for submitting updates to its approved LTPP. Comments should specifically address the feasibility of instituting a common numbering system (common to all three IOUs) in order to track revisions to the LTPP. This numbering system would be akin to that currently utilized to track tariff revisions." In addition, the Scoping Memo sought proposals from the IOUs regarding streamlining opportunities for filings in its Volume II testimony.
The IOUs each addressed the issues raised in the Scoping Memo in their own way and to varying degrees of completeness and adequacy. SCE, between its LTPP and its draft Rulebook, might have provided the Commission with the most complete listing of the various compliance filings currently required, while PG&E and SDG&E provided a much less detailed accounting. Essentially, each IOU files different versions of the above-referenced filings in order to demonstrate compliance with a Commission-approved AB57 procurement plan.
We do not take specific issue with any of the IOUs' recitation of the information contained in each LTPP regarding the number, type and scope of the various required compliance filings. Therefore, we do not make a specific ruling related to that aspect of their procurement plans. We do, however, raise several tangential issues related to periodic compliance reporting, as well as general compliance, and we address these below.
Outside of the IOUs' filed LTPPs and their initial briefs, virtually no other party provided input regarding how and to what extent the Commission could improve and/or streamline the reporting requirements. The apparent lack of attention paid to this topic by parties is particularly troubling to this Commission especially given that one of the main complaints from parties is that the LTPP proceeding presents parties with such a "mountain of information" that it is "near impossible to make sense of it all." And yet, when we specifically seek input on this matter - not once, but twice - intervenors fail to provide us with a record upon which we can make an effective, informed decision.215
As SDG&E correctly points out, many of the existing procurement rules were put together in a relatively short period of time as the Commission established a regulatory framework that allowed the utilities to resume procurement on January 1, 2003. Although the Commission has at various stages clarified rules, this proceeding creates an additional opportunity to learn from four years of practice and adopt changes that will maintain proper regulatory oversight while eliminating duplicative workload on the Commission, the utilities, and stakeholders.
The Scoping Memo issued in this proceeding stressed the importance of this procurement proceeding by specifically stating:
"A key objective of this proceeding is to review and approve updated 2006 Long-Term Procurement Plans that supersede all previously approved plans, as modified.
Although some of the activities detailed in the approved STPPs have not changed, it is necessary for the Commission to have an updated, complete 2006 LTPP. The complete 2006 LTPPs will merge the contents of the two previous filings, include the AL amendments proposed by each utility over the past several years, and reflect the Commission's numerous decisions on procurement policies and transactions. It may appear that the Commission is asking for a large amount of information in Attachment A; however, since the "approved plans" are currently scattered in numerous plans, decisions, ALs-it is necessary for the plan components to be consolidated in one place.216
Therefore, the Commission's request to streamline and increase the transparency of the compliance process should be a high priority for all parties to this proceeding. While the lack of a more fully developed record limits our ability to make certain changes to the procurement process, we will rely on the record available, as well as the Commission's own experience and expertise, to make incremental changes with the expectation of undertaking a more comprehensive process review in the next LTPP.
An example of our disappointment is evidenced by the complete lack of attention paid to our explicit request for comment on "...the feasibility of instituting a common numbering system (common to all three IOUs) in order to track revisions to the LTPP. This numbering system would be akin to that currently utilized to track tariff revisions." No party addressed this request.
As such, we direct the IOUs to develop a common numbering system in order to track revisions to each Commission-approved LTPP. We repeat our guidance that this numbering system would be akin to the system currently utilized to track tariff revisions.217 The FERC-approved CASIO tariff could also serve as a model. As we have stated several times in the Scoping Memo and throughout this decision: Part of the challenge of determining compliance with Commission procurement rules is simply determining which procurement plan is the "latest and greatest" for each IOU.
Having a tariff-like numbering system in place combined with a redline strikeout method of proposing updates to the LTPP should go a long way in reducing the amount of confusion surrounding these procurement plans and this proceeding in general. This updating process should be fairly straight forward for all parties given that this proceeding has combined all the previous procurement plans into one document (potentially with several volumes and attachments). We direct the utilities to work with ED staff to develop this tariff-like numbering system.
D.04-12-048 FOF 106 states that updates or modifications to an IOU's procurement plan between the biennial procurement plan filings should be filed with an advice letter. We have found that this process, as defined in our prior decision, is inadequate. Thus, we require all updates proposed between the biennial procurement plan filings (via the Advice letter process) to include redlined pages of the existing procurement plan as well as "cleaned up" replacement pages which include the tariff-like numbering system discussed above. This system should alleviate much of the confusion expressed by parties regarding an inability to determine what the "latest and greatest" currently in effect procurement plan actually is. We require the IOUs to implement this tariff-like numbering system when they make their compliance filing to submit the conformed 2006 long-term procurement plans discussed below. In addition, to address the lag time between this decision and the compliance filing, we require that all advice letters seeking modifications to the approved LTPP filed in the interim include redlined versions of the corresponding pages of the filed 2006 LTPPs.
The Commission currently requires each IOU to submit a Quarterly Compliance Report (QCR) via the Commission's advice letter process within 30 days of the end of every calendar quarter, in order for Commission Staff to review the IOU's procurement transactions for compliance with the Commission-approved procurement plan and its up-front and achievable standards and criteria.
D.04-12-048 directed the IOUs to file a joint proposal to reformat the quarterly procurement transaction compliance report to provide the Commission concise and coherent information.
PG&E, SCE and SDG&E have worked collaboratively to draft a proposed streamlined quarterly procurement transaction compliance report and have discussed the proposal with Energy Division. Since filing testimony in the 2006 LTPP, the IOUs have held additional discussions with the Energy Division with the hope of reaching agreement on the format standardization proposal. Once an agreement is reached, PG&E recommends the Commission adopt the reformatted report. PG&E states that, in order to make meaningful changes and improvements to this report, the Commission should direct the Energy Division to promptly review and approve or modify the IOUs' proposal on the format and contents of this report.
SCE states that, since early 2005, the IOUs have worked collaboratively to develop a standardized format for the QCRs and accompanying electric, natural gas and financial transaction workpapers, submitted in conjunction with each utility's AB 57 procurement plan. Earlier this year, preliminary standardization results were shared with the Energy Division and important feedback was received.
SCE believes that the Commission will find that the final proposed joint format for the QCRs strikes the optimal balance between many interests, including, but not limited to, streamlining of the QCR process to improve efficiency and facilitate a timely review and approval process, providing the public with greater access to information, and preserving the confidentiality of market sensitive data.
In the future, as it pertains to MDR and other aspects of the IOUs' QCR advice letter submittals, SCE suggests that the Commission may want to take into account any recommendations that the Energy Division's external auditors may make while submitting their audit review reports. SCE also observes that the amount of data that is currently required to be submitted is very voluminous, and that this in itself might be a root cause of Energy Division's inability to review the QCRs in a short time-frame. If so, the Commission might want to consider reducing the data submittal requirement to transaction details only, with the rest of the material to be made available upon request by the Energy Division. In addition, SCE believes that its Procurement Rulebook will provide a convenient guide for the Energy Division in reviewing SCE's transactions for compliance with its procurement plan.
The QCR and its workpapers include transaction details as well as a wide variety of supporting documents, including all the items listed in the Commission's Master Data Request,218 for all transactions entered into the calendar quarter.
ED has not been able to review and approve the QCRs in a timely manner consistent with the 30-day schedule that the Commission earlier adopted for such review.219 At the time the IOUs were required to submit their LTPPs, only the 2003 transactions have been reviewed and approved by the Energy Division. Earlier this year, ED retained an external auditor to review all of the 2004, 2005 and 2006 transactions.220 This review by the external auditors is nearly complete with audit review reports on 2007 transactions expected in 2008. However, this represents a very long review and approval process. As an example, the transactions executed in Q1 2004 were not approved by ED for almost three years. Clearly, this is unacceptable.
Once the external auditors complete their final review and offer any recommendations, the Commission will revisit the transaction review and approval process, including the elements contained in the QCR Master Data Request (MDR).221 However, we see no valid reason for waiting until the middle of 2008 to examine the QCRs. Part of the contract entered into with the external auditors requires them to make recommendations to the Energy Division when they submit the audit reports. Therefore, we direct the Energy Division, in conjunction with the external auditors and the IOUs, to continue the collaborative effort formed earlier this year and develop a reformatted QCR. We direct ED staff to submit a project timeline to the service list of this proceeding, within 30 days of issuance of this decision, which provides sufficient time for public comment. We delegate authority to Energy Division to authorize the implementation of the reformatted and streamlined QCRs as well as the authority to continue to make ministerial changes to the content and format of the report as needs arise.222
We also note that the QCRs represent thousands of transactions per IOU per quarter that must be reviewed and approved in order to assure compliance with the approved LTPPs. As such, we shall increase the timeframe for approving the QCRs from the current 30-day requirement to 60 days. This modification should be fairly non-controversial since, as noted above, none of the QCRs to date have been approved anywhere close to 30 days from the end of the quarter.
We take this opportunity to address the administrative and technical components of the compliance review process, and place resource needs in perspective. As a result, for the reasons explained below, we authorize the Executive Director to hire and manage one or more contractors to perform certain tasks, with cost recovery from ratepayers through the IOUs that are respondents to the Commission's long-term proceeding.
The Commission initiated long-term procurement plan proceedings to continue our efforts to ensure a reliable and cost-effective electricity supply in California. Each LTPP proceeding serves as the umbrella proceeding for the Commission to consider, in an integrated fashion, all of the Commission's electric resource procurement policies and programs, including implementation of directives from other procurement related proceedings. The LTPP proceedings operate on a two-year cycle, with IOUs responsible for submitting procurement plans that project their need over a 10-year horizon.
Beginning with the 2006 long-term planning proceeding, we intend that the approved LTPPs supersede all previous procurement plan authority as granted in R.04-04-003 and R.01-10-024. This decision not only approves the 2006 LTPPs, with modifications described in this decision and exclusive of new policy proposals or proposed policy modifications not addressed herein, but also establishes a skeleton upon which future LTPP filings in the biennial cycle may build and grow. It identifies the key issues and areas of planning that the IOUs must address and improve upon in their future LTPP filings. As such, this and subsequent LTPP proceedings represent significant undertakings that touch on many of the Commission's energy-related activities and policy goals. The staff of the Commission must coordinate and consider, in an integrated fashion, all of the Commission's electric resource procurement policies and programs, including implementation of directives from other procurement proceedings relevant to this cycle. In addition, this proceeding is the forum in which we consider potential future policies that the federal government, state legislature, the CEC or the Commission may implement that will impact the procurement practices of California's utilities. This is an immense undertaking for the Commission and its staff.
The three IOUs expend roughly 11 billion dollars annually on electricity procurement, and this number is growing rapidly.223 This is a huge expenditure of ratepayer dollars, and the policy and implementation detail requirements and refinements set forth in this and past LTPP decisions represent the Commission's best efforts to control these costs.
Needless to say, implementation and administration of this program is an immense task involving a plethora of technical details and Commission resources. We identify in this decision a number of tasks that will benefit from additional expertise that can supplement Commission resources. Therefore, we authorize the Executive Director to hire and manage a contractor (or contractors) to provide technical support to assist staff in the following areas:
· General program design, implementation and evaluation (including process improvements and compliance assurance);
· Design and evaluation, in coordination with the IOUs, of a more rigorous portfolio evaluation approach to long term resource planning, as encouraged by many parties to this proceeding; and
· Other tasks staff identifies to promote LTPP program goals and maintain a reliable, cost-effective, and environmentally sound electric supply in California.
To support these resources, SCE, PG&E and SDG&E are each authorized to establish an LTPP Technical Assistance Memorandum Account (LTAMA). The Commission will send approved invoices issued by contractors or invoices issued by the Commission for reimbursement of costs incurred by the Commission to PG&E, SCE and SDG&E for payment of these technical assistance costs on a pro rata basis (i.e., 33.3% to each IOU) unless the contractor(s) perform work related to only a specific utility. PG&E, SCE, and SDG&E are authorized to record these charges into the LTAMA, and each company may later apply for recovery in rates. We shall limit costs that may be charged to the LTAMA to a $400,000 annual cap.
3.6.4. SCE & PG&E Petition to Modify D.02-12-074 & D.04-12-048
On December 2, 2005, SCE and PG&E filed a petition to modify D.02-12-074, and D.04-12-048 to change the requirement that energy utilities must file a periodic report on their ERRA with the Commission from a monthly report to a quarterly report.224 In their petition to modify, SCE and PG&E requested that the Commission modify D.02-12-074 and D.04-12-048 to allow each utility to submit one quarterly ERRA summary report with a monthly breakdown of costs to the Commission's Utility Audit Finance and Compliance Branch (CUAFCB), and to make all supporting documentation available to the Branch upon request, rather than submitting a 1,000-page ERRA report every month.
PG&E correctly notes in its brief that the Commission recently acted on the petition to modify by issuing D.07-04-020, agreeing to reduce the amount of supporting documentation but still requiring the utilities to file monthly rather than quarterly.225 Therefore, this issue is now moot. However, PG&E's characterization of the Commission's ruling on this matter is inaccurate and we feel the need to clarify. D.07-04-020 denied the request to change the monthly ERRA filing to quarterly filings, but granted the request that the utilities only supply a breakdown of costs with their ERRA monthly filings and make all supporting documentation available to Commission Staff and interested parties upon request.
We further directed that "if Commission Staff or interested parties request supporting documentation, the utility must comply with the request within 10 business days. Furthermore, pursuant to Public Utilities Code Section 314.5, if Commission Staff deems it necessary to review any supporting documentation being maintained at the utilities' offices, upon request the utilities are to grant Commission Staff access to their offices."226 Therefore, PG&E's characterization that the information only be available to the UACFB is incorrect.
Throughout the body of this decision we make several significant modifications to the proposed LTPPs of the IOUs. In order to reflect all of the guidance provided here - in one, comprehensive, going-forward long-term procurement plan - we shall require the IOUs to file conformed long-term procurement plans through a compliance filing. This conformed "2006 long-term procurement plan" would "...supersede all previously approved plans, as modified...The complete 2006 LTPPs will merge the contents of the two previous [LTPP] filings, include the AL amendments proposed by each utility over the past several years, and reflect the Commission's numerous decisions on procurement policies and transactions."
We direct the IOUs to file the conformed 2006 LTPPs, via a compliance filing no later than 90 days from the date of this decision.227 The conformed 2006 LTPPs shall incorporate all of the directives contained in the body of this decision as well as any updates filed through the Commission's Advice Letter process between the issuance of this decision and the due date of the compliance filing. We direct the utilities to work with the Energy Division to develop a format for the compliance filing. In addition, we recognize that the extensive changes necessary to the LTPPs base on this decision may be difficult to complete within 90 days and we hereby delegate to the Executive Director the authority to defer the filing for up to an additional 90 days.
In the interim, each IOU's 2006 LTPP is adopted with the modifications stipulated in this decision and summarized in the Ordering Paragraphs and the Compliance Table provided as Attachment E (and exclusive of any policy proposals embedded in the Plans that are not specifically addressed in this decision).
We recognize that this requirement, and the extensive nature of the LTPP filings in general, are process-focused and potentially burdensome to all parties involved. As more structured, transparent procurement policy and compliance guidelines such as those established in this decision are incorporated into the IOU procurement "culture," though, we are optimistic that they will lead to greater efficiencies and a simplification of this process than currently exist in this proceeding.
In comments on the Proposed Decision, SCE stated that the language contained in the PD does not adequately explain the specific changes that the utilities are required to make in their compliance filings. We shall provide more clarity as to the Commission's expectations of the compliance filing by providing limited examples drawn from the utilities LTPPs filed on December 11, 2006.228
The discussion contained in SCE's LTPP regarding the Energy Auction229 is now incomplete and must be updated to include a discussion of the completion of phase I of this proceeding. For instance, the Commission issued D.07-09-044, Opinion Adopting Joint Settlement Agreement, as Clarified, Regarding Principles for the Energy Auction Process and Products, and the issuance of this decision should be reflected in SCE's LTPP.
In addition, SCE's LTPP references an outstanding petition for Modification of D.06-07-029.230 This discussion is incomplete and must be updated, as part of the compliance filing, to include a discussion of the Commission's ruling on SCE's Petition. The Commission issued D.07-06-022, which denied SCE's request.
Further, SCE's LTPP discusses the Commission's policy on debt equivalence.231 This decision modified the Commission's debt equivalence (in RFO bid evaluation) policy and, as such, the compliance filing should include an updated discussion on the topic of debt equivalence.
Similarly, in Volume II of its LTPP (Section VII. D. Changes in SCE's Collateral Requirements) SCE seeks Commission approval to increase its collateral capacity limit up $2.0 billion. SCE's request is granted in this decision, and as such, in its compliance filing, SCE should modify its LTPP top reflect this approval (Volume IA, Section 3B).
We also note that recently each IOU asked for modifications to their AB 57 procurement plans to obtain congestions revenue rights (including long-term CRRs).232 This requested modification to the existing procurement authority was granted by the Commission in a series of Resolutions. The Resolutions were issued after December 11, 2007, and included in the Resolutions were various `criteria for implementation,' and as such the IOUs must include the new procurement authority in their respective compliance filings.
As noted above, we direct the utilities to work with ED to further refine the scope and format of the compliance filing if necessary.
136 D.02-08-071, D.02-10-062, D.03-12-062 and D.04-12-048.
137 DRA, Volume A at 28 (Khosrowjah).
138 SCE Reply Testimony at 16.
139 PG&E Reply Testimony at 3-9
140 Non-confidential information is determined pursuant to the confidentiality matrix in D.06-06-066 and D.07-05-032.
141 DRA, Volume A at 29 (Khosrowjah).
142 DRA, Volume A at 29 (Khosrowjah).
143 Aglet at 1-7 (Reid).
144 PG&E Reply Testimony at 3-9.
145 SCE Reply Testimony at 18.
146 Aglet at 1-9 (Reid).
147 DRA, Volume A at 29 (Khosrowjah).
148 PG&E Reply Testimony at 3-10.
149 SCE Reply Testimony at 19.
150 AReM at 27 (McClary).
151 DACC at 6 (Hoegger).
152 CCSF at 3 (Casey).
153 SDG&E Reply Testimony at 7-8 (McClenahan).
154 SCE Reply Testimony Vol. 1 at 15.
155 Named for the Cost Allocation Method from D.06-07-029.
156 Subject to applicable confidentiality provisions.
157 No CAM Group member can be a wholesale market participant or represent a wholesale market participant. The details of the qualifications and participation of CAM Group Non-PRG members are explained in the CAM Group proposal in Attachment D.
158 The form and content of the NDA will be resolved before activation of the CAM Group. The creation of the NDA cannot delay the effective period of the CAM Group.
159 D.04-12-048.
160 TURN Initial Comments.
161 PG&E Volume II at II-17.
162 SCE Volume II at 49.
163 SDG&E Volume II at 10.
164 PG&E Volume II at II-17.
165 SCE Volume II at 49.
166 SCE Reply Comments.
167 SDG&E Volume II at 11.
168 SDG&E Reply Comments.
169 PG&E Volume II at II-18.
170 SCE Volume II at 49.
171 NRG Initial Comments.
172 DRA Initial Comments.
173 The IOUs will have until January 1, 2009 to work through the IE interviewing and selection process. In the mean time, the IOUs may continue to contract with existing IEs for all 2008 RFOs; however, we encourage the IOUs to explore the use of different IEs for successive 2008 RFOs. Any RFO issued on or after January 1, 2009 shall only use an IE that is a member of the approved IE pool. All changes to the IE process within this decision will go into effect prospectively beginning January 1, 2009.
174 Based upon DRA's and the IOUs' comments on the PD, successive rotation through the IE pool will not be required; however, the IOU must seek approval from ED of the selected IE for each RFO. ED reserves the right to deny approval of the use of a particular IE.
175 IOUs shall expand their IE pool as needed to maintain a minimum of three IEs and/or to add additional IEs as the IOU finds suitable candidates.
176 Candidate names shall be kept confidential as part of the PRG process.
177 Inclusion of an IE in the IE pool does not require the signing of a contract between the IOU and the IE.
178 Once the IE pool is established, the IOU may select an IE only from that pool of candidates and only after notifying the PRG and ED of the selected candidate. The IOU shall submit the preferred IE name to the PRG and ED no less than 15 days before the IE begins work on the RFO contract. Based upon the recommendation of DRA in its comments on the PD, ED shall have final approval of the use of the selected IE for each RFO.
179 If an IOU wishes to remove an IE from the pool, it must communicate this to its PRG and to ED.
180 Review of an IE does not preclude the IE from continuing to remain in the IE pool. Reevaluation gives all interested parties, including the IOU, its PRG and ED an opportunity to evaluate the suitability of the IE for continued participation in the pool.
181 We encourage the three IOUs to work together in an attempt to find a pro forma contract that is acceptable to all three companies.
182 Based upon the IOUs comments received on the PD, IEs will no longer be restricted from participating in two different IOUs' RFOs within the same six month period. Such a prohibition may lead individual IEs to contract solely with one IOU, thus, potentially reducing the overall independence of the evaluator.
183 IOUs that seek ERRA recovery for IE expenses must submit notice of this change via advice letter to the Commission.
184 Competitive RFOs include RFOs issued to satisfy service area need and supply-side resources not including EE and DR.
185 This requirement creates uniformity between the product length for which the IOU must consult its PRG and the IE process.
186 ED may expand upon the questions and information to be addressed in the IE report template listed above based upon its findings during the template creation process.
187 For contracts less than five years, IE reports shall be submitted with the QCR, as mentioned previously.
188 ED may expand upon the questions and information to be addressed in the project application template listed above based upon its findings during the template creation process.
189 SDG&E Opening Brief, p. 51.
190 SCE Opening Brief, p. 51.
191 SCE's Opening Brief, pp. 53-55.
192 PG&E Opening Brief, p. 59.
193 A detailed description of the RFO process, including a thorough explanation of the evaluation metrics should be submitted as part of the RFO Application Template directed elsewhere in this decision.
194 IOUs should be continually improving and refining their bid criteria and bid evaluation processes based on lessons learned in past RFOs, including lessons learned from their RPS solicitations.
195 That notice however, also stated that the Russell City project's permit was on appeal and therefore also in doubt.
196 For example, the bid evaluation might take into consideration a bid that is more expensive but has a greater likelihood of resulting in a viable project.
197 See Vantage Consulting, Evaluation of Credit & Collateral Requirements for the Commission, February 22, 2007.
198 In this context, "debt equivalence" (also called "imputed debt") is a tool used by credit rating agencies to assess potential financial risks associated with a utility's PPA obligations. In certain circumstances, a rating agency may treat some portion of PPA costs as payments on debt obligations rather than as operating costs (treating them as "debt equivalent"), and in turn make corresponding adjustments to the utility's credit metrics and financial ratios used as part of the rating agency's overall assessment of credit quality.
199 D.04-12-048, p. 144.
200 D.04-12-048, p. 145.
201 D.04-12-048, p. 144.
202 D.04-12-048, pp. 144-145.
203 D.04-12-048, pp. 144-145. In practice, the three utilities use the adopted 20% risk factor in a calculation to determine a "bid adder" for debt equivalence that is added to the cost of a PPA for purposes of bid evaluation. See Exh. 96, p. 12 (Meal/IEP).
204 D.04-12-048, p. 145.
205 The record in this proceeding includes numerous submissions, analyses, and discussions regarding the issue of DE and the various approaches taken by the three major rating agencies (Moody's, Fitch and S&P) and while we do not repeat the record in this decision we assure parties that we have weighed the entire record in reaching our decision.
206 FIN 46 (R), Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51, issued in 2003 by the Financial Accounting Standards Board (FASB). FIN 46(R) was issued to provide guidance on the identification of and financial reporting for, entities over which control is achieved through means other than voting rights. Such entities are called variable-interest entities (VIE). FIN 46(R) stipulates that a contract to purchase the entire output of a single plant entity at something other than a fixed price constitutes a "variable interest" in that entity. The "primary beneficiary" of a VIE's activities must consolidate the financial statements of the VIE when issuing the primary beneficiary's financial statements.
207 SDG&E Opening Brief, August 1, 2007, p. 53, citing Schneider Testimony, Exhibit 40, pp. 215-16.
208 The Transparency Working Group submitted a Status Report on August 30, 2007. On September 26, 2007, the Working Group submitted an Updated Status Report to summarize the results of two additional meetings. How transmission is considered in the RFO process was also raised in the AB 1576 Repowering Working Group, but parties agreed to move the topic to the Transparency Working Group since the issue applies more broadly to project bid evaluation rather than strictly to repowering projects.
209 SDG&E's experts did not make presentations at the meeting, but did attend via teleconference and commented that SDGE generally treats transmission costs in the same manner as SCE and PG&E.
210 All references to contracts in this discussion include any extension options provided for in the contract.
211 SCE helpfully expresses TEVaR 95% another way, as the difference between the potential electric portfolio cost at the 95% level (a "high cost" scenario) and the expected electric cost (the "medium cost" scenario).
212 Originally, SCE and for SDG&E kept confidential the values for CRT (one cent per kWh) and PRG notification trigger (125% of CRT), while PG&E did not. We understand the importance of confidentiality in commercial negotiations that the utilities engage in to procure hedges, but we believe that publishing these metrics and guidelines will not unduly harm the utilities' negotiating positions, since by now these numbers have been published in several places, including Attachment A to the Scoping Memo in this proceeding.
213 Some of the utilities report also TEVaR 95%.
214 Attachment A, p. 21.
215 We note that "Commission Review and Implementation of Procurement Plan" is explicitly listed as a topic in the September 25 Scoping Memo as well as in a May 2, 2007 Administrative law Judge's Ruling, both issued in this proceeding - R.06-02-013.
216 Scoping Memo pp. 15-16.
217 See GO 96-B, Section 8.4.2 Tariff Sheet Numbering.
218 See D.02-10-062 COL 7, OP 8 and Appendix B for details.
219 See p. 46, Paragraph 2, of D.02-12-074 for details.
220 This external review process has been extended to include the 2007 Quarterly Compliance Reports.
221 This review will not be limited to the QCRs. As stated above, when the Commission initiates the next LTPP proceeding, we fully intend to undertake a comprehensive review of the Commission's AB 57 long-term procurement compliance and review process.
222 In addition, we note that several of the directives contained in this decision impact the QCRs and we expect the ED collaborative effort to incorporate the necessary changes.
223 See Table 1 and related discussion on pp. 9 and 10 of the Scoping Memo.
224 In discussions between SCE and the Commission's Utility Audit and Finance Compliance Branch ("UAFCB"), UAFCB indicated that the sheer volume of ERRA related data submitted to the Energy Division each month causes major storage problems for the staff. A typical monthly ERRA report, including supporting documentation, consists of a few pages of summary information and approximately 1,000 pages of supporting documentation. Thus, the Commission's UAFCB is burdened with approximately 24,000 pages per year of monthly ERRA report documentation from SCE and PG&E.
225 D.07-04-020.
226 Id., p. 4.
227 We direct each IOU to separately file a Tier 3 Advice Letter when it submits its Compliance Filing for approval.
228 We acknowledge that all three IOUs made subsequent updates to their filings after the initial December 1, 2006 filing date. However, relying on the initial filings for the purpose of providing the requested clarity for the compliance filing should not result in any concerns. These examples are to serve illustrative purposes only and are not intended to be all-inclusive or definitive.
229 Volume 1A of SCE's LTPP (Section II. F. 5. Energy Auction (R.06-02-013)
230 Volume 1A of SCE's LTPP filing (Section II. F. 6. Petition For Modification of D.06-07-029) p. 46.
231 Volume 1A of SCE's LTPP (Section III. A. 7. b) Debt Equivalence) p. 68.
232 SCE filed AL 2142, SDG&E filed AL 1920 and PG&E filed AL 3095 to modify their AB 57 procurement plan to enable each IOU to procure Long-Term CRRs. The Commission approved the requests in Resolution 4117, Resolution 4124, and Resolution 4122, respectively.
SCE filed AL 2141, SDG&E filed AL 1926 and PG&E filed AL 3106 to modify their AB 57 procurement plan to enable each IOU to procure CRRs. The Commission approved the requests in Resolution 4134, Resolution 4136, and Resolution 4135, respectively.
