3. Overview of RPS Program and 2007 Plans
Pursuant to the RPS Program, each electrical corporation and retail seller is required each calendar year to procure, with some exceptions, a minimum quantity of electricity from eligible renewable energy resources as a percentage of total retail sales. This is generally known as the annual procurement target, or APT. Each electrical corporation is also required, with some exceptions, to increase its total procurement from eligible renewable energy resources by at least 1% of retail sales per year until it reaches 20%. This is generally known as the incremental procurement target, or IPT, and results in incremental growth in the APT. (§ 399.15.)
To fulfill these requirements, each electrical corporation must prepare a Plan for the procurement of renewable energy. The Plan must include, but is not limited to (a) an assessment of demand and supply to determine the optimal mix of renewable resources, (b) use of compliance flexibility mechanisms established by the Commission, and (c) a bid solicitation. The Commission must review and accept, modify or reject each electrical corporation's Plan prior to the commencement of renewable resource procurement. (§ 399.14.)
Pursuant to the August 21, 2006 Scoping Memo, each IOU submitted its 2007 Plan on or about September 25, 2006. Each Plan describes the actions the IOU will undertake in order to meet its 2007 APT, 2007 IPT and other RPS targets as it proceeds to ultimately procure 20% of its retail sales from eligible renewable resources by 2010. Each Plan includes resource planning information, a protocol or a request for offer (RFO), and one or more master purchase and sale agreements. The Plans are briefly described below.
3.1. PG&E
PG&E estimates its 2007 APT is about 11,687 gigawatt-hours (gWh), and its 2007 IPT is approximately 750 gWh.2 In its 2007 Solicitation, PG&E seeks to procure approximately 1% to 2% of its retail sales volume, or approximately 750 to 1,500 gWh.
PG&E states that, starting in 2007, it will require more capacity to meet its reserve margin requirements, as well as additional peaking energy resources to meet its net energy requirements. After 2007, PG&E says it will require additional dispatchable peaking and shaping resources to meet energy and capacity requirements for all subperiods. PG&E reports that it is particularly interested in projects that will begin commercial deliveries during 2008, given that a significant number of deferred incremental deliveries (otherwise due in 2004 and 2005) are now due in 2008.
PG&E's proposed 2007 Plan and draft master purchase and sale agreements are similar to those used in 2005 and 2006. PG&E seeks Power Purchase Agreements (PPAs) with delivery terms of 10, 15 or 20 years beginning in 2007 or beyond. Participants may also propose delivery terms between 10 and 20 years. Participants may submit offers for four specific products: (a) as-available, (b) baseload, (c) peaking, or (d) dispatchable. PG&E states that it will also consider two types of combination products: (a) peaking or dispatchable plus as-available, or (b) peaking plus other firm deliveries in any combination of other time-of-delivery (TOD) periods.
In addition to purchases, PG&E will also consider three ownership alternatives. These are: (a) purchase and sale agreement (in which the developer sells the project to PG&E for a pre-determined price at the time the project enters commercial operation), (b) a PPA with PG&E buyout option (in which the developer gives PG&E the option to purchase the facility at a pre-determined price after it has been in operation for a certain number of years), and (c) sites for development (in which a participant offers a new or existing site controlled by participant (with land rights assigned to, or purchased by, PG&E) for PG&E to, in turn, develop, construct and operate an RPS facility).
PG&E states that it will evaluate offers using several factors. These are: (a) market valuation, (b) portfolio fit, (c) credit and finance, (d) project status, (e) technology viability and participant experience, (f) supplier diversity, (g) adjustment for transmission cost adders and integration costs, and (h) materiality and cost impact of any proposed modification to the standard contract.
PG&E assumes the regulatory environment in 2007 will be substantially the same as before, except for new RPS provisions as a result of SB 107, effective January 1, 2007. PG&E identifies six differences between its 2006 and 2007 proposed solicitations:
1. Updated TOD factors (based on recent forward market prices for natural gas and wholesale power).
2. An expanded Dispatch Down Period (wherein PG&E may curtail a unit upon request up to 50 hours per year in order to improve integration of facilities with overall operations).
3. Reduction of collateral requirements during project development (retaining adequate collateral to encourage performance but reducing requirements on projects with smaller capacity factors, on a megawatt-hour (mWh) basis).
4. Request that participants whose projects have delivery points outside the California Independent System Operator (CAISO)-controlled grid provide two separate prices (one for delivery onto the CAISO grid, and one for delivery outside the CAISO grid).
5. Elimination in redundancy of evaluation protocols.
6. Terms are conformed to changes in statute pursuant to SB 107.
PG&E estimates that it will meet its 2007 IPT, but may not achieve its 2007 APT, and may need to utilize flexible compliance to meet that obligation. Further, PG&E estimates it will meet its 2010 APT, but may need to use flexible compliance provisions, given that construction of new facilities will take time and delay the commencement of deliveries for a period of several years after contract execution.
3.2. SCE
SCE estimates its 2007 APT is 14,998 gWh, and its 2007 IPT is 779 gWh.3 SCE states that its 2007 planned procurement activities include seeking resources to augment those under contract as a result of prior solicitations, and those executed as a result of the 2005 and 2006 solicitations, to the extent necessary to ensure that SCE meets the overall 20% goal.
SCE says it has received relatively few bids that do not require significant transmission upgrades for delivery of the energy. Transmission will continue to be a serious impediment, according to SCE, and increased procurement activity (e.g., executing more contracts) will not accelerate the planning, permitting and construction of necessary transmission. Unlike its 2006 Plan, SCE's 2007 Plan does not develop high, medium and low procurement need scenarios based on a range of forecasts for key variable (e.g., retail sales). Nonetheless, SCE says its overall goal is to achieve 20% as soon as possible.
SCE's 2007 Plan and protocol are similar to those in 2006. SCE says it will consider timely proposals from existing or new projects located within or outside California. These include new or repowered facilities that operate on co-fired fuels or a mix of fuels that include fossil fuel hybrid. SCE seeks proposals based upon standard term lengths of 10, 15 or 20 years, and each proposal must be at least one megawatt (MW). SCE prefers delivery at SP-15,4 but will consider other proposals.
SCE says it will evaluate proposals based on criteria intended to achieve the lowest ratepayer cost and the best fit with utility retained generation and California Department of Water Resources generation. SCE states that it takes into account the criteria in the Commission's least-cost best-fit (LCBF) decision (D.04-07-029). For example, SCE indicates that quantitative benefits and costs are incorporated into proposal-specific benefit/cost ratios used to rank proposals, with qualitative attributes used to screen and adjust final ranking. Quantifiable values are evaluated using a production simulation model to calculate total system production costs and benefits associated with the renewable generating facility, and capacity benefits are developed by incorporating Effective Load Carrying Capacity values, according to SCE. Quantified costs also include transmission, integration and debt equivalence. Non-quantified attributes include seller's capability to perform, seller experience, seller technical expertise, and environmental impacts. Finally, SCE says it will utilize attributes identified by the Commission in D.04-07-029 as qualitative methods for evaluating tie-breakers.
SCE identifies the following significant differences between its 2006 and 2007 proposed Procurement Plans:
1. Scheduling Coordinator (SC)
a. SCE will provide SC services.
b. SCE includes disposition of CAISO charges and a penalty in order to allocate costs relative to SCE providing these services.
2. Wind Projects
a. SCE includes new performance standards to allow sellers to adjust proposed prices and address elimination of commercially available wind turbine manufacturer guarantees.
b. SCE includes new standards for meteorological equipment to address changing standards for this equipment.
SCE estimates that it may neither achieve its 2007 IPT, nor its 2007 APT, absent application of flexible compliance rules. Nonetheless, SCE's goal is to achieve 20% as soon as possible, whether or not that goal can be accomplished by 2010. SCE reports that it is positioned to meet the goal by 2013, if not before. (SCE Plan, pp. 2 and 5.)
3.3. SDG&E
SDG&E states that its 2007 APT is 905 gWh, and its 2007 IPT is 164 gWh.5 SDG&E says it expects to exceed both its 2007 APT and IPT, and will bank surpluses for future compliance. SDG&E anticipates achieving the goal of procuring 20% of its retail sales via renewables by 2010. In addition, however, SDG&E says that results from the 2004 and 2005 RFOs validate SDG&E's concerns that availability of transmission will have a significant impact on SDG&E's ability to achieve the 20% by 2010 goal, particularly new transmission that may be needed to import energy from Imperial Valley, Tehachapi and eastern San Diego County.
SDG&E says its RFO will solicit capacity and energy services from repowered generation, upgraded plant, or new facilities, and the RPS products may include unit firm or as-available deliveries starting in 2008, 2009, 2010 or 2011. SDG&E seeks proposals for 10, 15 or 20 years, but will consider other contract durations subject to Commission approval. The 2007 RFO allows sellers to offer renewable products from generation plants connected anywhere in the Western Electricity Coordinating Council (WECC) transmission system, as long as the energy is delivered into California.
SDG&E indicates that it also intends to evaluate a number of ownership opportunities. These include turnkey development, PPAs with ownership options after commercial operation, and building its own renewable generation.
SDG&E says that bids will initially be ranked based on an all-in price, including costs or credits related to capacity, energy, transmission upgrades, congestion, and integration. Bids will also be ranked, according to SDG&E, based on duration equalization adders and debt equivalence adders, if applicable. SDG&E indicates it will use production cost modeling to evaluate LCBF from offers that have made its short list. Qualitative factors will be used as tie-breakers of similar cost offers, according to SDG&E, including such factors as benefits to minority and low income areas, resource diversity, environmental stewardship (including the Commission Water Action Plan), ability to advance the schedule for commercial operation, technology and operational flexibility, reliability, development risk, financing plan, corporate capabilities, credit and proven experience.
SDG&E intends to issue an RPS RFO in 2007. Further, SDG&E reports that it has made it a practice, to the extent feasible, to include renewables in non-RPS RFOs. SDG&E says it may do so again if it issues an all-source RFO during 2007.
SDG&E explains that RPS contracts may affect SDG&E's credit rating due to the effects of debt equivalence and financial reporting consolidation potentially required under FIN 46(R) rules.6 In recognition of possible costs from this reduced credit rating, SDG&E requests Commission authorization to recover costs associated with rebalancing its capital structure to the authorized capital structure. SDG&E proposes to do this by seeking relief in advice letters filed with the Commission for approval of individual RPS contracts.
SDG&E identifies several changes between the 2006 and 2007 Plans, the more significant being:
1. Clarification regarding acceptance of offers from anywhere in the WECC system as long as the energy is delivered to a CAISO delivery point.
2. Clarification regarding how bids are evaluated and ranked as part of the LCBF process.
3. Consideration of SDG&E building its own plants by 2010.
4. Clarification regarding bidders submitting two bids when the project relies on any third party awards (e.g., Supplemental Energy Payments (SEPs), Production Tax Credits, Investment Tax Credits), with one price if funding is available, and one price if funding is unavailable.
2 PG&E's 2007 Procurement Plan, page 6. This is an APT of about 1,668 average megawatts (aMW) at an 80% capacity factor (CF). This is an IPT of about 107 aMW at an 80% CF.
3 SCE's 2007 Procurement Plan, Attachment 1. This is an APT of about 2,140 aMW at an 80% CF. It is an IPT of about 111 aMW at an 80% CF.
4 Path 15 is a transmission interface located in the southern portion of PG&E's service area that is in the middle of the CAISO control area. It is comprised of several high voltage lines, and runs approximately 90 miles between the Los Banos and Gates substations in the San Joaquin Valley. SP-15 is the zone south of Path 15. (D.03-05-083, pp. 11-12.)
5 SDG&E's 2007 Plan, page 4. This is an APT of about 129 aMW at an 80% CF. It is an IPT of about 23 aMW at an 80% CF.
6 Financial Accounting Standards Board Interpretation No. 46(R), referred to as FIN 46(R). SDG&E says no PPA has been deemed subject to consolidation until now but new, more restrictive financial reporting rules may increase instances wherein SDG&E must consolidate a seller's financial information with SDG&E's own financial reports to the Securities and Exchange Commission. (Plan, p. 19.)
