ALJ/CAB/sid DRAFT Agenda ID #7556 (Revision 1)
Ratesetting
5/29/2008
Decision PROPOSED DECISION OF ALJ BROWN (Mailed 4/15/2008)
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA
In the Matter of the Application of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) for Approval of Results of Fast Track of Its New Generation Request for Offers and for Cost Recovery. |
Application 07-02-026 (Filed February 28, 2007) |
(See Appendix A for a list of appearances.)
DECISION GRANTING APPLICATION OF SOUTHERN
CALIFORNIA EDISON COMPANY FOR APPROVAL OF
CONTRACT WITH BLYTHE ENERGY, LLC
1. Summary
This decision grants the application by Southern California Edison Company (SCE) for approval of a contract that was selected from SCE's fast-track request for offers (RFO) for new generation that could be on-line by August 2010. In its application, SCE seeks approval of two contracts, an offer from Blythe Energy, LLC (Blythe) for up to 490 megawatts (MW) of expected capacity and energy, and an offer from CPV Ocotillo, LLC (CPV)1 for up to 455 MW of capacity and energy. Due to intervening circumstances regarding the timing on the completion of a study on the delivery of the power from Blythe, a separate decision on CPV was prepared.2 This present decision only approves the 10-year power purchase agreement (PPA) with Blythe. SCE requests, and we grant, the authority to allocate the benefits and costs of the Blythe PPA to all benefiting customers in accordance with Decision (D.) 06-07-029.
2. Background
On February 16, 2006, the Commission opened Rulemaking (R.) 06-02-013 to continue its efforts to ensure a reliable and cost-effective electricity supply in California through the integration of a comprehensive set of procurement policies and review of the long-term procurement plans (LTPP) of the three investor-owned utilities (IOUs). In Phase 1 of the proceeding, the Commission examined the need for additional policies to support new generation and long-term contracts in California. This effort resulted in D.06-07-029, where the Commission adopted a cost-allocation mechanism that allows the advantages and costs of new generation to be shared by all benefiting customers in an IOU's service territory.
Due to an amalgamation of regulatory and economic factors, private investment in California generation was not keeping up with the state's growing resource needs, especially when that growth is coupled with the expected retirements of many aging power plants. The investment community indicated that it needed the certainty of long-term contracts to get financing for new generation projects, but both the IOUs and the other load serving entities (LSE) were reluctant to sign long-term contracts.
In D.06-07-029, the Commission established a cost-sharing mechanism designed to spur development of new electric resources by designating the IOUs as the procurers of new generation for the benefit of their entire service territory. The IOUs were directed to solicit long-term contracts for electricity from new generation facilities and the cost and benefits of the capacity and energy from the contracts would be shared with all benefiting customers in the IOUs' service territories, including bundled service customers, direct access (DA) customers and community choice aggregation (CCA) customers.3
The decision further advised SCE to issue an RFO seeking up to 1,500 MW of new generation resources.4 In response to that order, SCE issued an RFO on August 14, 2006. In the RFO, SCE solicited two types of offers: (1) fast-track projects that could come on-line on or before August 1, 2010; and (2) standard-track projects that could be available on or before August 1, 2013. The Blythe and CPV contracts are the choices SCE made from the fast-track offers.
2.1. Fast-Track RFO
As SCE set forth in its testimony supporting its application, the RFO asked for offers for the sale of electrical capacity, energy, ancillary services and resource adequacy benefits from new resources that could be on-line by August 1, 2010. SCE received offers from 18 projects that could potentially meet the on-line date. Based on the final bid prices received, SCE accepted the Blythe and CPV offers.
Pursuant to D.06-07-029, SCE was required to use an Independent Evaluator (IE) to oversee any solicitation leading to the procurement of resources where the benefits and costs would be shared with all benefiting customers. SCE testified that it engaged Sedway Consulting, Inc. as the IE. SCE provided Sedway Consulting with all the data and materials it needed to perform an independent evaluation of the offers from the RFO.5 In a separate report, the IE concluded that "SCE conducted a fair and effective evaluation of the offers that it received in response to its Fast Track solicitation and made appropriate selection decisions."6
On February 15, 2007, SCE signed a 10-year PPA with Blythe for up to 490 MW of expected baseload capacity and associated energy from the Blythe Energy Center, including a 2x1 combined cycle generating turbine and supporting generation equipment. The Blythe Energy Center has been operating since December 2003 and is currently connected to the Western Area Power Administration (WAPA) grid.
The proposed PPA between Blythe Energy Center and SCE requires the Blythe Energy Center to be disconnected from WAPA and interconnected to the California Independent System Operator (CAISO) grid by a new 67-mile direct radial connection to an existing substation within the south-of-path (SP) 15 control area. The project qualifies as a new resource pursuant to the requirements articulated in SCE's RFO. The project has a 30-year design life, a direct radial transmission line connection into the CAISO grid to provide incremental capacity into SP 15, and satisfies CAISO's requirements to qualify as an SP 15 resource including execution of interconnection studies and agreements.
Consistent with Federal Energy Regulatory Commission policy, the 67-mile radial transmission line or "gen-tie" needed to connect the generation project to the integrated transmission network within SP 15 will be fully funded by the generation developer itself, so that construction of this line will impact neither transmission owner costs nor general transmission rates charged to recover such costs.
3. Application for Blythe
SCE filed an application on February 28, 2007, seeking the following findings:
¬ That SCE's conduct in respect to the fast-track RFO was reasonable; and
¬ That the Blythe PPA is needed to preserve system reliability; that the contract is reasonable and prudent; that the Blythe payments are recoverable in full through rates or other Commission authorized cost recovery mechanism, subject only to SCE's prudent administration of the contract; and that SCE is to allocate the costs and benefits of the Blythe contract to all benefiting customers in accordance with D.06-07-029.
A prehearing conference was held on March 27, 2007. On April 2, 2007, the Division of Ratepayer Advocates (DRA) was the only party that filed a protest. Based on the limited issues raised in the protest, one day of evidentiary hearing (EH) was scheduled for May 30, 2007.
DRA served intervenor testimony, as did Californians for Renewable Energy (CARE). CARE, DRA and SCE participated in the EH; CARE, DRA and SCE filed post-hearing opening briefs; and DRA and SCE filed reply briefs.
CARE requested an opportunity for the citizens of Blythe, California to share their views on the power plant with the Commission. A public participation hearing (PPH) was held on July 12, 2007, in Blythe and numerous Blythe and Mesa Verde residents attended and participated.
3.1. Intervenors
DRA
DRA consistently has argued that the energy from the CPV PPA is not needed until 2011, and therefore the Commission should not approve the contract with an on-line date of August 1, 2010. DRA alleges that if the start date of the resource can be postponed until 2011, ratepayers will save millions of dollars. In summary, DRA does not address whether or not the Blythe PPA is an appropriate choice from the RFO, but only whether the resource is needed in 2010 when it is scheduled to come on-line.
DRA argues that the Commission's directive in D.06-07-029 to SCE to solicit up to 1,500 MW of new generation was not a pre-approval of SCE's need for more resources. SCE still has to justify its need numbers going forward, and DRA claims SCE did not meet that burden. To begin, DRA argues that SCE presented "no fewer than four (4) sets of projected need numbers between the time of the filing of the Application [February 28, 2007] and the time of this brief [June 20, 2007]."7 From DRA's perspective, the use of different forecast numbers by SCE makes it difficult for anyone to do a thoughtful analysis of what SCE's need actually is at any particular point in time. DRA argues that the different need tables are not easily comparable because they use varying imputs for planning reserves and operating reserves, as well as present need numbers assuming a "worst-case scenario." In some tables, the projected retirement numbers are different, and in other tables SCE reduces its forecast for demand response programs to comport with updated information. DRA cross-examined SCE's witness Minick on the differing forecast numbers, and Minick suggested "split the difference."8
DRA recommends that SCE use the more substantiated California Energy Commission (CEC) forecast for demand beyond 2007, that indicates a demand of 28,511 MW total for SP 15, instead of SCE's own forecast that shows a need of 29,062 MW. DRA argues that SCE should not rely on its own forecast when that forecast is so significantly different from the CEC forecast, and SCE failed to present adequate justification for the difference. When DRA develops its own forecast for SP 15, using the CEC forecast, DRA finds that "SCE posts a robust 2,073 MW of excess capacity in 2010."9
Therefore, based on this forecast, DRA urges the Commission to deny the application for the Blythe resource because ratepayers will save many millions of dollars if the PPA is delayed until SCE actually has a need for the resource.
CARE
CARE also questions whether the energy from Blythe is needed. From CARE's analysis of SCE's data, CARE claims that SCE fails to present any empirical basis for its assumptions about plant retirements, and therefore CARE argues that SCE has no evidentiary record to support building new facilities. CARE's primary concern, however, is whether the Blythe facility's production of greenhouse gas emissions has been adequately considered and addressed. CARE requested, and received, the PPH in Blythe so that CARE's membership in the Blythe area would have an opportunity to address the Commission on the total environmental impacts they think will result from utilizing the Blythe facility, including the loss of agriculture lands.
4. Discussion
4.1. Need for Blythe PPA
D.06-07-029 stated that California needs new capacity on line as soon as 2009, especially in Southern California. The primary stated purpose of Phase I of R.06-02-013 was to incentivize new generation in the state and break the stalemate wherein neither the utilities nor the merchant generators had been willing to invest in the construction of new capacity.
To that result, D.06-07-029 directed SCE to solicit bids for up to 1,500 MW of new generation resources. SCE followed that instruction, and conducted a RFO seeking new generation that could be on-line by 2010. The Blythe facility, along with CPV, were chosen to ensure that up to 945 MW of new generation could be on-line by August 1, 2010. As mentioned, the CPV facility was addressed in a separate decision.
It appears based on the testimony submitted by SCE in support of its application, and the Independent Report by the IE, that SCE conducted its RFO in a fair and reasonable manner and the selection of Blythe is an appropriate selection.
However, DRA takes the position that SCE still has an affirmative obligation to justify its need for these resources. We are also cognizant of DRA's argument that using multiple need tables-all of which use different assumptions and produce different need numbers-makes it difficult to conduct a thoughtful and thorough analysis of the data.
However, as SCE argued, forecasting is not an exact science. As SCE's forecast witness Minick stated, his load forecasts change with time and due to changes in other assumptions and circumstances.10 Minick testified that SCE modified the numbers between the time SCE filed its application on February 28, 2007, and the date of the EH, May 30, 2007. For example, Minick made assumptions for San Diego Gas & Electric Company's peakers, but that assumption was reduced by 120 MW.11 Minick also lowered SCE's demand-management program projections 275 MW.12 Minick also explained that SCE used different assumptions, and therefore reached different need forecasts, between its best-estimate plan and its required-plan. In that regard, SCE's best-estimate plan had a lower implementation of the California Solar Initiative (CSI) than did the required plan, based on the CSI target SCE actually thought it would achieve.13
Minick also modified SCE's estimates of potential generic retirements. Minick, as well as other SCE witnesses, indicated that it was difficult to predict when the owner of an aging plant would decide that it was no longer economic to keep the plant on-line, and retire the facility.
In addition to the fact that the data in any one forecast is constantly updated as SCE receives new information, SCE also produced different "need" scenarios from high need to base case. When Minick was asked what was common among all the different need tables, he responded that "[T]he need grows rather dramatically between, let's say, 2009 and '10, '11 and '12. It is based on a lot of factors, but in most cases it grows so quickly that it will absorb quite a few megawatts from year to year . . . ."14 Continuing on, Minick indicated that SCE finds a need in its base case in 2011, and in the high need scenario as early as 2007 and 2008.
Factors in the economic, political and regulatory world are also always in flux. Just recently, the Arizona Corporation Commission rejected SCE's application for approval of the Devers-Palo Verde 2 transmission line from California to Arizona, which SCE had expected to provide approximately 900 MW of new capacity to California starting in 2009.15 SCE is continuing to pursue this transmission line, but even if it is ultimately approved, there will be a significant delay.
Therefore, it is difficult, if not impossible, for any party to accurately predict a future need number for SCE and whether or not the energy from the Blythe facility will be needed as early as August 1, 2010, when it is slated to come on-line. However, it appears reasonably certain that SCE will need additional resources by 2011, and under some assumptions, much sooner. Furthermore, when DRA asked SCE's witness Cini whether the start date of Blythe could be postponed from 2010 to 2011 his response was "that would effectively kill the contract."16 Therefore, the Commission's option is to either approve the Blythe contract with the start date of August 1, 2010, or deny SCE's application.
The Commission is therefore faced again with the need to be provident and prudent when it is not prescient. While we strive to keep electric rates just and reasonable, and procuring excess power could increase the cost to ratepayers, having SCE caught in 2010 with insufficient electricity in its portfolio will definitely increase the cost to ratepayers. When a utility is "short" on its resources, the cost of covering that short fall has historically exceeded the cost of power from resources under ownership or contract. Emergency resource planning is expensive and often the utility does not get the best resources. Reasonable resource planning allows for better prices and better resources.
Therefore, after reviewing the different need tables presented by SCE, weighing the difficulty SCE has in predicting future plant retirements with a specific degree of certainty, and factoring in the unknowns currently associated with the Devers-Palo Verde 2 transmission line, we find that it is reasonable to approve SCE's application for approval of the Blythe PPA with the start date of August 1, 2010.
We find that the RFO conducted by SCE pursuant to our directive in D.06-07-029 was fair and reasonable and that the choice of this resource was also reasonable. Since this resource was selected to meet the system needs of SP 15, the costs and benefits of the Blythe PPA should be spread among all benefiting customers pursuant to the cost allocation mechanism established in D.06-07-029.
4.2. Applicability of SB 1368 and the Commission's Greenhouse Gas Emissions Performance Standards
The California Legislature passed Senate Bill (SB) 1368 on August 31, 2006 and Governor Schwarzenegger signed the bill into law on September 29, 2006. Section 2 of SB 1368 adds Public Utilities Code Section 8341(a), which provides that "No load-serving entity or local publicly owned electric utility may enter into a long-term financial commitment unless any baseload generation supplied under the long-term financial commitment complies with the greenhouse gases emission performance standard established by the commission, pursuant to subdivision (d)."
In order to institute the provisions of SB 1368 the Commission instituted R.06-04-009. The proceeding resulted in the establishment of a GHG emissions performance standard (EPS), for carbon dioxide (CO2 ) D.07-01-039 noted, "SB 1368 establishes a minimum performance requirement for any long-term financial commitment for baseload generation that will be supplying power to California ratepayers. The new law establishes that the GHG emissions rates for these facilities must be no higher than the GHG emissions rate of a combined-cycle gas turbine (CCGT) powerplant."
The CCGT-equivalent emissions limit adopted by the Commission is 1,100 pounds of CO2/MWh.
The Decision further explains:
SB 1368 describes what types of generation and financial commitments will be subject to the EPS ("covered procurements"). Under SB 1368, the EPS applies to "baseload generation," but the requirement to comply with it is triggered only if there is a "long-term financial commitment" by an LSE. The statute defines baseload generation as "electricity generation from a powerplant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%. ... For baseload generation procured under contract, there is a long-term commitment when the LSE enters into "a new or renewed contract with a term of five or more years."
SB 1368 provides that CCGT baseload powerplants currently in operation, or that have a CEC final permit decision to operate as of June 30, 2007, shall be "deemed to be in compliance" with the EPS.
The "Adopted Interim Rules for Greenhouse Gas Emissions Performance Standard" are attached to D.07-01-039 as Attachment 7.
By this application SCE requests that the Commission approve the long-term power purchase contract with Blythe Energy, LLC. Although, in general, this "new contract commitment with a term of five years or greater,"17 would be subject to the EPS, the Blythe PPA is exempt from such regulations.
The Blythe project is an existing operating CCGT generating unit that will be newly interconnected to the CAISO control area under the terms of the contract. As such, Blythe Energy is "deemed compliant" with the EPS rules.18
4.3. Transmission Upgrade Uncertainties
A number of transmission upgrades associated with the Devers-Palo Verde #2 Transmission Project (DPV2) were assumed in conjunction with the transmission studies conducted for these projects. It is uncertain at this time when and if DPV2 will be constructed. Consequently, the CAISO performed new Reliability and Deliverability Studies for the project without the DPV2 upgrades.
The results of the new Reliability Study indicate that the West of Devers Special Protection System recently implemented by SCE mitigates the Blythe reliability concerns and deliverability limitations west of Devers under contingent conditions, so the proposed project will be able to reliably interconnect to the grid once the developer performs several interconnection upgrades identified in the study.
The Deliverability Study found that the project is 96% (500 MW/520 MW) deliverable under the study's existing conditions. SCE has indicated in response to an Energy Division (ED) Data Request that it would not have selected a different fast-track offer based on the latest deliverability findings, and ED concurs with this assessment. SCE has also indicated that additional system upgrades in the near future may allow the project to be fully deliverable.
4.4. Compliance with EAP Loading Order
D.04-12-048 and D.07-12-05219 require IOUs to utilize the Energy Action Plan (EAP) loading order when conducting procurement. To that end, one of the primary goals of the Commission's ongoing LTPP Proceeding is to serve as the Commission's forum to integrate all procurement policies and related programs and serve as the check-in point on the EAP loading order. The focus of the Commission's review of the IOU's LTPPs is to ensure that the near-term policies and practices of IOU procurement can be made consistent with a set of Commission approved upfront standards and to ensure that the long-term resource plans demonstrate the appropriate portfolio management approaches. The Commission examines the LTPPs to verify that the IOUs are taking appropriate steps to procure resources that prioritize the loading order from the EAP; are consistent with the state's energy policy; maximize preferred resources, while also optimizing least cost/best fit and maintaining reliability. The Commission will not approve plans that lack realistic and implementable provisions for meeting the EAP targets.
Among other things, each LTPP planning cycle includes expectations of the supply of various procurement resources, including energy efficiency, demand response, renewables, distributed generation and non-renewable generation over the long-term time horizon. Some of the other procurement dockets have established targets, goals, and policies that affect the supply of certain procurement resources in the short or longer terms. In each LTPP, and subsequent request for new generation, the utility must demonstrate that the choices it makes are consistent with a Commission-approved 10-year resource plan designed to exist within any and all policy constraints and that will enable the IOU to adequately meet its bundled customer load needs.
There is no explicit discussion in the fast-track application addressing the EAP loading order. However, SCE's 2006 LTPP provided information on how it complied with Commission directives on the loading order, and the SP-26 resource need tables provided in this proceeding were developed consistent with SCE's standard planning methods and its LTPP. SCE's 2006 LTPP states that the utility "...strives to ensure that the State's EAP and Loading Order are followed through its efforts to plan, implement and administer cost-effective and reliably achievable demand-side management (DSM) programs and its continued national leadership in procurement from renewable resources." (Section III.A.4 of Volume 1A of SCE's 2006 LTPP, entitled "How SCE Follows the Loading Order When Making Procurement Decisions.") SCE goes on to describe three specific actions it takes to ensure its procurement decisions are consistent with the EAP:
o First, prior to every competitive procurement for conventional resources (e.g., fossil fuel sources) SCE updates its procurement needs by first refreshing the latest forecasts for DSM programs, any renewable procurement, and any QF [qualifying facility] procurement to ensure conventional procurement is last in filling its procurement needs. That is, conventional resources are used for "residual" procurement.
o Second, SCE does not "close out" its energy needs via conventional procurement multiple years forward. Instead, it layers in procurement needs over time (ratably), which ensures that conventional resources do not "crowd out" preferred resources.
o Finally, SCE applies a greenhouse gas adder to all contracts greater than five years in duration.
4.5. Least-Cost, Best-Fit Evaluation
D.04-12-048 requires the IOUs to utilize a least-cost, best-fit (LCBF) methodology when evaluating RFO bids.20 While SCE does not explicitly describe a LCBF methodology in its application, the process employed in evaluating bids and selecting RFO winners was described in significant detail. In response to an ED data request, SCE provided additional details on the confidential specifics of their LCBF methodology. Based on this supporting documentation, ED has confirmed that SCE satisfied its LCBF methodology requirement.
5. Conclusion
We evaluated SCE's application for approval of the Blythe PPA in light of the following factors: conduct of the RFO; need for new capacity in SCE's service territory; need for new capacity by August 1, 2010; applicability of SB 1368 and GHG emissions; transmission delivery; compliance with the EAP loading order; and LCBF evaluation. In summary, we make the following findings:
1. SCE's conduct in respect to the fast-track RFO and the selection of Blythe was reasonable;
2. The Blythe PPA is needed to preserve system reliability and there is no precise certainty as to whether the need for power from Blythe will be significantly greater in 2011 than in August 2010 when Blythe is scheduled to come on line;
3. The Blythe facility is an existing operating CCGT generating unit that will be newly interconnected to the CAISO control area under the terms of the contract and is therefore "deemed compliant" with the EPS rules;
4. The most recent CAISO Reliability Study indicates that the Blythe facility can reliably interconnect with the grid once the developer performs several interconnection upgrades identified in the study;
5. The most recent CAISO Deliverability Study indicates that the project is 96% deliverable under current system conditions;
6. SCE's 2006 LTPP indicated that SCE complied with the EAP loading order in assessing what resources were needed to meet the needs of its service territory; and
7. SCE utilized a LCBF methodology in evaluating the Blythe bid against other bids in the fast-track RFO.
We therefore approve SCE's application for approval of the Blythe PPA. Consistent with the PPA, payments to Blythe will begin when the project comes on-line. In addition, we find that the Blythe payments are recoverable in full through rates, subject only to SCE's prudent administration of the contract, and that the costs and benefits of the Blythe PPA are to be allocated to all benefitting customers in accordance with D.06-07-029.21
6. Comments on Proposed Decision
The proposed decision (PD) of the administrative law judge (ALJ) in this matter was mailed to the parties in accordance with Section 311 of the Public Utilities Code and comments were allowed under Rule 14.3 of the Commission's Rules of Practice and Procedure. Comments to the PD were received from Californians for Renewable Energy (CARE) and SCE. SCE's comments urged swift adoption of the PD so that SCE could get one step closer to getting the Blythe facility on-line to ensure that ratepayers have adequate resources to avoid "emergency resource planning" that is expensive and often less than optimal.
CARE, on the other hand, requests that the Commission not approve the Blythe facility because of unresolved issues on the Federal Energy Regulatory Commission's (FERC) docket and on review before the United States Court of Appeals, Ninth Circuit (Ninth Circuit), that could affect the Blythe facility and because CARE does not believe environmental issues were adequately addressed.
To begin, CARE worries about the greenhouse gas (GHG) emissions from the plant. From CARE's perspective, it is not right to have the residents of Blythe suffer the consequence of the emissions from the plant, but the electricity generated by the Blythe facility will be used by SCE customers hundreds of miles away. CARE recommends locating the plant closer to the load center. In addition, the Blythe plant uses fresh water for cooling that would otherwise be available for agricultural uses, and that has resulted in fewer orchards and farms, and a loss of jobs for many agricultural workers. Finally, CARE objects to the location of the power plant, not just because of its distance from the SCE load center and its use of fresh water, but also because the plant was built on a site sacred to local people.
The FERC issues are also of concern to CARE because as CARE argues in its comments, the terms of the contract between SCE and Blythe could be changed by decisions by FERC and the Ninth Circuit, and SCE ratepayers could end up paying substantial monetary damages. CARE represents the poor and under-represented who are the least able to pay an increase in their electric bills if SCE is subject to monetary penalties for changing the terms of the contract.
On July 12, 2007, the Commission held a PPH in Blythe and listened to the comments presented by Blythe and Mesa Verde residents. Many of these speakers echoed the statements made by CARE about the siting of the facility on sacred grounds, the loss of agricultural jobs, and the concerns over all the GHG emission from the plant. The Commission has listened to and considered the comments from the PPH and the arguments raised by CARE.
Today, the only issue before the Commission is whether to approve the PPA between SCE and Blythe. Siting decisions were made years ago by the California Energy Commission (CEC). The Blythe facility was approved by the CEC, built by Blythe Energy, and is now fully functional. This Commission is only weighing whether the 10-year PPA for the output from the facility is needed by SCE to serve the needs of its system, and whether the choice of this resource to fill that need is reasonable. Based on our findings set forth in the decision, we find that the contract is needed and is a reasonable selection by SCE from its RFO.
In addition, we are aware of the outstanding FERC and Ninth Circuit issues and the possibility that a final decision on some of these issues could affect the Blythe/SCE contract. If there are monetary consequences as a result of changes to the terms of the contract, we will address at that time how to fairly allocate those costs. The FERC issues, as well as those on appeal in the Ninth Circuit are inchoate at this time, so we can not base this decision on unknown future possibilities.
On May 12, 2008, SCE filed a reply arguing that CARE did not present a valid reason for rejecting or postponing the PD, and urged the Commission to promptly adopt the PD.
7. Assignment of Proceeding
President Michael R. Peevey is the assigned Commissioner and Carol A. Brown is the assigned ALJ in this proceeding.
8. Scoping Memo
On March 12, 2007, the Chief Administrative law Judge issued a ruling preliminarily confirming the applicant's proposed categorization of ratesetting and that no hearing is necessary. Pursuant to Rule 7.3 of the Commission's Rules of Practice and Procedure, no scoping memo issued. Following the PHC on March 27, 2007, it was determined that evidentiary hearings were necessary and they were scheduled for May 30-31, 2007.
The preliminary determination that no hearing is necessary is changed to hearing is necessary.
1. We find that SCE's conduct in respect to the fast-track RFO was reasonable.
2. We find SCE's choice of the Blythe PPA from the other offers in the fast-track RFO is reasonable.
3. The Blythe PPA is needed to preserve system reliability when the facility is scheduled to come on-line in August 2010.
4. There is no certainty as to whether the need for the power from Blythe will be significantly greater in 2011 than in August 2010 when Blythe is scheduled to come on-line, so it is reasonable to approve the contract for 2010 delivery.
5. The Blythe facility is an existing operating CCGT generating unit that will be newly interconnected to the CAISO control area under the terms of the contract and is therefore "deemed compliant" with the EPS rules.
6. Consistent with Federal Energy Regulatory Commission policy, the 67-mile radial transmission line or "gen-tie" needed to connect the generation project to the integrated transmission network within SP 15 will be fully funded by the generation developer itself, so that construction of this line will impact neither transmission owner costs nor general transmission rates charged to recover such costs.
7. The most recent CAISO Reliability Study indicates that the Blythe facility can reliably interconnect with the grid once the developer performs several interconnection upgrades identified in the study.
8. The most recent CAISO Deliverability Study indicates that the project is 96% deliverable under current system conditions.
9. SCE's 2006 LTPP indicated that SCE complied with the EAP loading order in assessing what resources were needed to meet the needs of its service territory.
10. SCE utilized a LCBF methodology in evaluating the Blythe bid against other bids in the fast-track RFO.
11. We find that the Blythe payments should be recoverable in full through rates, subject only to SCE's prudent administration of the contract.
12. We find that the costs and benefits of the Blythe PPA are to be allocated to all benefitting customers in accordance with D.06-07-029.
1. The 10-year Blythe PPA for up to 490 MW of capacity and energy deliverable from August 1, 2010 through July 31, 2020 is reasonable and should be approved.
2. The costs and benefits of the Blythe PPA should be shared with all benefitting customers in SCE's service territory in accordance with the cost allocation methodology adopted in D.06-07-029.
IT IS ORDERED that:
1. We authorize Southern California Edison Company (SCE) to enter into a 10-year power purchase agreement (PPA) with Blythe Energy, LLC (Blythe) for up to 490 megawatts of capacity and energy deliverable from August 1, 2010 through July 31, 2020.
2. We authorize SCE to allocate the costs and benefits of the Blythe PPA with all benefitting customers in accordance with the cost allocation methodology adopted in Decision 06-07-029.
3. Application 07-02-026 is closed.
This order is effective today.
Dated __________________, at San Francisco, California.
************** PARTIES ************** |
Janine L. Scancarelli |
Peter Skala |
Diane I. Fellman |
Valerie J. Winn |
(END OF APPENDIX A)
1 The CPV Ocotillo, LLC has since been renamed CPV Sentinel LLC; however, to avoid confusion and to remain consistent with the name provided in SCE's application, the project is referred to as CPV Ocotillo in this decision.
2 On April 10, 2008, the Commission approved the CPV contract in Decision (D.) 08-04-011.
3 D.06-07-029 at pp. 7, 25-27. Benefitting customers are defined as all bundled service customers, DA customers, and CCA customers. Benefitting customers are also other customers who are located within a utility distribution service territory, but take service from a local POU subsequent to the date new generation goes into service.
4 Id. at pp. 47, 62-63.
5 The IE prepared an Independent Evaluation Report, Exhibit 7.
6 Exhibit 7, p. 1.
7 DRA Opening Brief, June 20, 2007, p. 5.
8 Id., p. 6, citing RT, p. 53.
9 Id., p. 10.
10 "The forecast in the amount of resources in future years changes with time. Sometimes it goes up, sometimes it goes down." Tr., 31:6-8.
11 Tr., 38:19-20.
12 Tr., 38:22-28, 39:1.
13 Tr., 41:4-14.
14 Tr., 91:15-19.
15 SCE's Opening Brief, June 20, 2007, pp. 2-3.
16 Tr., 181:10-11.
17 D.07-01-039, Attachment 7, p. 3.
18 Id., Section 1(d).
19 At the time SCE filed its application for approval of both Blythe and CPV, only the decision on the 2004 LTPP proceeding, D.04-12-048 was extant. In December 2007, the Commission issued D.07-12-052 on the 2006 LTPP. For any Commission direction on procurement protocols applicable to the Blythe and CPV PPAs, reference to either LTPP decision is appropriate since there is no difference in the 2007 decision that would affect our consideration of these projects.
20 D.04-12-048, Finding of Fact 86 and Ordering Paragraph 26d.
21 We recognize that the benefits of the project are not fully available at this time due to the CAISO Deliverability Study's finding that the project is only 96% deliverable under existing system conditions. However, because this fact would not have affected the project's selection in the RFO, we conclude that all benefitting customers should be allocated the full share of costs and available resources associated with this project.
