Word Document PDF Document

PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E-4377

REDACTED

RESOLUTION

Resolution E-4377. Pacific Gas and Electric Company (PG&E) requests approval of five renewable power purchase agreements with Solar Projects Solutions, LLC for solar photovoltaic generation.

PROPOSED OUTCOME: This Resolution approves cost recovery for five renewable energy power purchase agreements (PPA) between PG&E and Solar Projects Solutions, LLC (SPS) with conditions. The SPS Alpaugh 50, LLC PPA is approved without modification. The SPS Alpaugh North, LLC, SPS Atwell Island, LLC, SPS Corcoran, LLC, and SPS White River, LLC PPAs are approved with modification.

ESTIMATED COST: Costs of the PPAs are confidential at this time.

By Advice Letter 3613-E filed on February 10, 2010.

__________________________________________________________

SUMMARY

Pacific Gas and Electric Company's (PG&E) five renewable power purchase agreements (PPAs) with Solar Projects Solutions, LLC (SPS) comply with the Renewables Portfolio Standard (RPS) procurement guidelines. The SPS Alpaugh 50, LLC PPA is approved without modification. The SPS Alpaugh North, LLC, SPS Atwell Island, LLC, SPS Corcoran, LLC, and SPS White River, LLC PPAs are approved with modification.

PG&E filed Advice Letter (AL) 3613-E on February 10, 2010, requesting California Public Utilities Commission (Commission) review and approval of five PPAs to procure power from five solar photovoltaic (PV) facilities owned by SPS subsidiaries: SPS Alpaugh 50, LLC (Alpaugh), SPS Alpaugh North, LLC (Alpaugh North), SPS Atwell Island, LLC (Atwell), SPS Corcoran, LLC (Corcoran), and SPS White River, LLC (White River). SPS is a joint venture between Enco Utility Services, LLC (ENCO) and Samsung Green Repower, LLC (Samsung).

The Alpaugh PPA is approved without modification. The Alpaugh North, Atwell, Corcoran, and White River PPAs are ordered to be modified as described herein to require the projects under those PPAs to pursue qualification as resource adequacy (RA) resources if Small Generator Interconnection Procedures (SGIP) are revised such that small generators may qualify as RA resources. With this modification, the PPAs are consistent with PG&E's 2009 RPS Procurement Plan. Additionally, deliveries from the PPAs are reasonably priced and fully recoverable in rates over the life of the PPAs, subject to Commission review of PG&E's administration of the PPAs.

The following tables summarize the SPS PPAs:

Generating Facility

Technology Type

Contract Term (Years)

Capacity (MW)

Minimum

Energy (GWh/yr)

Commercial Operation

Date

Project Location

Alpaugh

Solar PV

25

50

64

2/1/2013

Tulare County

Alpaugh - North

Solar PV

25

20

27

11/1/2012

Tulare County

Atwell Island

Solar PV

25

20

27

6/1/2012

Tulare County

Corcoran

Solar PV

25

20

27

10/1/2012

Kings County

White River

Solar PV

25

20

27

7/1/2012

Tulare County

BACKGROUND

Overview of the Renewables Portfolio Standard (RPS) Program

The California RPS Program was established by Senate Bill (SB) 1078, and has been subsequently modified by SB 107 and SB 1036.1 The RPS program is codified in Public Utilities Code Sections 399.11-399.20.2 The RPS program administered by the Commission requires each utility to increase its total procurement of eligible renewable energy resources by at least one percent of retail sales per year so that 20 percent of the utility's retail sales are procured from eligible renewable energy resources no later than December 31, 2010.3

Additional background information about the Commission's RPS Program, including links to relevant laws and Commission decisions, is available at http://www.cpuc.ca.gov/PUC/energy/Renewables/overview.htm and http://www.cpuc.ca.gov/PUC/energy/Renewables/decisions.htm.

NOTICE

Notice of AL 3613-E was made by publication in the Commission's Daily Calendar. PG&E states that a copy of the Advice Letter was mailed and distributed in accordance with Section 3.14 of General Order 96-B.

PROTESTS

AL 3613-E was timely protested on March 9, 2010 by the Division of Ratepayer Advocates (DRA). PG&E responded to the protest of DRA on March 16, 2010.

DISCUSSION

PG&E requests Commission approval of five new renewable energy contracts

On February 10, 2010, PG&E filed AL 3613-E requesting Commission approval of five renewable PPAs with Alpaugh, Alpaugh North, Atwell, Corcoran, and White River for solar PV generation. The Alpaugh PPA, concerning a 50 megawatt (MW) facility, resulted from PG&E's 2008 RPS solicitation and was jointly bid by MMA Renewable Ventures, LLC (MMA RV) and ENCO. After MMA RV was sold to Fotowatio, S.L., ENCO became the sole developer of the project. Subsequently, ENCO entered an arrangement with Samsung America, Inc. by which both ENCO and Samsung agreed to jointly develop, construct and operate the Alpaugh project and various other projects. After ENCO and Samsung agreed to the joint venture, and while PG&E was negotiating the terms and conditions for the Alpaugh project, SPS offered additional projects to PG&E and the parties bilaterally negotiated the four additional PPAs for the 20 MW projects. All five projects will be located in California's San Joaquin Valley in Tulare and Kings Counties.

Procurement pursuant to the PPAs is expected to contribute a minimum of 172 gigawatt-hours (GWh) annually towards PG&E's Annual Procurement Target (APT) beginning in 2012.

PG&E requests that the Commission issue a resolution containing the following findings:

Energy Division evaluated the SPS PPAs for the following criteria:

Consistency with bilateral contracting guidelines

While the Alpaugh PPA originated from the PG&E's 2008 RPS solicitation, the other four SPS PPAs are the result of bilateral negotiations. In D.09-06-050, the Commission determined that bilateral contracts should be reviewed according to the same processes and standards as contracts that are the result of a competitive solicitation.4 Accordingly, as described below, Energy Division reviewed the four bilaterally negotiated SPS PPAs using the same standards used to review PPAs resulting from an annual solicitation. Applying this standard, the Alpaugh North, Atwell, Corcoran, and White River PPAs are consistent with the bilateral contracting guidelines established in D.09-06-050.

While PG&E has complied with the Commission's rules concerning bilateral contracts, we affirmatively state here, as stated previously, that the competitive solicitation process is preferred and should be the primary vehicle for RPS procurement.5 Besides the RPS solicitations that have taken place annually since the start of the RPS program, the Commission also recently approved PG&E's Solar PV program which is a five-year program to develop up to 500 MW of solar PV facilities in the range of 1 to 20 MW in PG&E's service area. 6 Of the 500 MW, PG&E is authorized to execute up to 250 MW in PPAs through competitive solicitations.

Consistency with PG&E's 2009 RPS Procurement Plan

California's RPS statute requires that the Commission review the results of a renewable energy resource solicitation submitted for approval by a utility.7 In AL 3613-E, PG&E asserts the SPS PPAs are consistent with its 2008 RPS Procurement Plan.8 Since the PPAs were executed after both the Commission had approved PG&E's 2009 RPS Procurement Plan (Plan) and PG&E had completed its 2009 RPS solicitation, Energy Division reviewed the SPS PPAs for consistency with PG&E's 2009 Plan.9 Pursuant to statute, PG&E's 2009 RPS Plan includes an assessment of supply and demand to determine the optimal mix of renewable generation resources, consideration of flexible compliance mechanisms established by the Commission, and a bid solicitation protocol setting forth the need for renewable generation of various operational characteristics.10

The stated goal of PG&E's 2009 Plan was to procure approximately 1-2 percent of retail sales volume or between 800 and 1,600 GWh per year of renewable energy in order to meet PG&E's RPS energy need.

The five SPS PPAs are consistent with PG&E's 2009 RPS Procurement Plan approved by D. 09-06-018.

Consistency with PG&E's Least-Cost Best-Fit (LCBF) Criteria

In D.04-07-029 the Commission directs the utilities to use certain criteria in their bid ranking. 11 The decision offers guidance regarding the process by which the utility ranks bids in order to select or "shortlist" the bids with which it will commence negotiations. PG&E's bid evaluation includes a quantitative and qualitative analysis, which focuses on four primary areas: 1) determination of a bid's market value; 2) calculation of transmission adders; 3) evaluation of portfolio fit; and 4) consideration of non-price factors. These criteria are explained in detail in PG&E's RPS Procurement Plan and in AL 3613-E.

The LCBF evaluation is generally used to establish a shortlist of proposals from PG&E's solicitation with whom PG&E will engage in contract negotiations. In this case, PG&E selected the Alpaugh project from its 2008 RPS solicitation using its LCBF evaluation methodology. The other four SPS PPAs resulted from bilateral negotiations and therefore did not compete directly with other RPS projects. In AL 3613-E, PG&E explained, however, that it evaluated the bilateral agreements using the same LCBF evaluation methodology it employed for evaluating the Alpaugh project. (See "Cost Reasonableness" for a discussion of how the SPS PPAs compare to PG&E's 2008 and 2009 solicitations and Confidential Appendix A for PG&E's LCBF evaluation of the SPS projects.)

PG&E evaluated the SPS PPAs consistent with the LCBF methodology identified in PG&E's 2008 RPS Procurement Plan.

Consistency with RPS standard terms and conditions (STCs)

The Commission adopted a set of standard terms and conditions (STCs) required in RPS contracts, four of which are considered "non-modifiable." The STCs were compiled in D.08-04-009 and subsequently amended in D.08-08-028.

The SPS PPAs include the current non-modifiable STCs consistent with D.08-04-009, as modified by D.08-08-028.

Contribution to RPS Minimum Quantity Requirements for Short-term Contracts with Existing Facilities

D.07-05-028 established a "minimum quantity" condition on the ability of utilities to count an eligible short-term contract with an existing facility for compliance with the RPS program.12 In the calendar year that a short-term contract with an existing facility is executed, the utility must also enter into long-term contract(s) or contract(s) with new facilities equivalent to at least 0.25% of the utility's previous year's retail sales.

These PPAs are considered long-term contracts because they are for more than 10 years in length, and the facilities that are to deliver energy pursuant to the PPAs are considered new because they will begin commercial operation after January 1, 2005. Therefore, the SPS PPAs will contribute to PG&E's minimum quantity requirement established in D.07-05-028.

Compliance with the Interim Greenhouse Gas Emissions Performance Standard (EPS)

California Pub. Utils. Code §§ 8340 and 8341 require that the Commission consider emissions costs associated with new long-term (five years or greater) power contracts procured on behalf of California ratepayers.

D.07-01-039 adopted an interim EPS that establishes an emission rate quota for obligated facilities to levels no greater than the greenhouse gas (GHG) emissions of a combined-cycle gas turbine power plant. The EPS applies to all energy contracts for baseload generation that are at least five years in duration.13

The PPA complies with the EPS established in D.07-01-039 because it concerns a renewable facility with a capacity factor less than 60 percent.

Project viability assessment and development status

PG&E believes the SPS projects are viable and will be developed according to the terms and conditions in the PPAs. PG&E evaluated the viability of the projects using the Commission-approved Project Viability Calculator, which uses standardized criteria to quantify a project's strengths and weaknesses in key areas of renewable project development. The confidential work papers for AL 3613-E included a comparison of the project viability scores relative to all bids PG&E received in its 2009 RPS solicitation and all shortlisted projects. Additionally, the IE Report states that the Alpaugh project ranks moderate in project viability and that the four 20 MW projects rank high in project viability.14

The SPS PPAs identify agreed-upon project milestones, including the construction start date and commercial operation date. The seller's obligations to meet these milestones are supported by performance assurance securities. PG&E asserts that the project development plans allow for all milestones to be achieved. PG&E provided the following information about the projects' developer and development status:

Site Control

PG&E represents that the developer has secured site control for each of the five project sites. SPS has 35 year lease agreements with the Alpaugh Irrigation District and Atwell Irrigation District.15

Resource and/or Availability of Fuel

PG&E represents that the solar resource is sufficient such that SPS is able to satisfy the terms and conditions of the PPAs. The projects do not require supplemental gas powered electrical generation facilities as backup.

Transmission

The delivery points for all the projects are within the CAISO interconnection area. Each project will require interconnection facilities to be built. Further confidential information concerning transmission for the projects is discussed in Confidential Appendix A.

Technology Type and Level of Technology Maturity

The projects will employ commercially proven PV panels.

Permitting

The projects require permits from Alpaugh Irrigation District, Atwell Water District, Corcoran Irrigation District, Tulare County, and Kings County.

Developer Experience

PG&E represents that ENCO, which was founded by Edison International in 1997, has experience in operating and maintenance services of electrical distribution, and that the parent company of Samsung America has developed solar projects in South Korea, Greece, Spain, Germany, and the United States.

Investment Tax Credit

PG&E represents that SPS has informed PG&E that the projects are eligible to receive investment tax credits and are seeking funding under the American Recovery and Reinvestment Act (ARRA) of 2009.

Equipment Procurement

Information concerning the stage of procurement of major components is included in Confidential Appendix A.

Commercial Online Date (COD)

Based on the above development milestone progress (site control, permitting, transmission, and financing status) to date PG&E asserts that the COD is reasonable.

Based on the above information and the additional confidential project viability information provided in AL 3613-E, PG&E asserts that the five SPS projects are viable and will provide renewable energy according to the terms and conditions in the PPAs.

Cost reasonableness evaluation

The Commission evaluates the reasonableness of each proposed RPS PPA price by comparing the proposed PPA to a variety of factors including RPS solicitation results and other proposed RPS projects. PG&E asserts that the PPAs are competitive relative to other offers PG&E received in its 2008 RPS solicitation and with other RPS procurement opportunities recently executed and under negotiation. In addition to evaluating the PPAs competitiveness to PG&E's 2008 RPS solicitation, the Energy Division also examined the reasonableness of the SPS PPAs against PG&E's 2009 RPS solicitation.16 Using this analysis, the Alpaugh PPA is reasonably priced given its high viability and value to ratepayers.

Confidential Appendix A includes a detailed discussion of the contractual pricing terms, including PG&E's estimates of the total contract costs under the Alpaugh PPA.

The total all-in costs of the Alpaugh PPA is reasonable based on its relation to bids received in response to PG&E's 2008 and 2009 RPS solicitations.

Payments made by PG&E under the Alpaugh PPA are fully recoverable in rates over the life of the PPA, subject to Commission review of PG&E's administration of the PPA.

Using the same cost reasonableness analysis the Alpaugh North, Atwell, Corcoran, and White River PPAs provide less value to PG&E than the Alpaugh PPA. While the five PPAs are similarly priced, the 20 MW projects will not provide resource adequacy value to PG&E under the proposed PPAs. This results in a material difference in the value of these projects. The IE ranks the four 20 MW contracts as low to moderate in net value versus moderate for the Alpaugh project.17 The IE further opines that these projects could improve their value to ratepayers if they were to qualify as resource adequacy capacity.

Under the current Small Generator Interconnection Procedures (SGIP), projects are subject to a feasibility study, system impact study, and facilities study, but not a deliverability study as required in the current Large Generator Interconnection Procedures (LGIP). As a result, projects interconnecting under SGIP cannot qualify for resource adequacy capacity. Thus, while the Alpaugh North, Atwell, Corcoran, and White River PPAs are highly viable, they are lower in value to the ratepayer than the Alpaugh PPA which has gone through the LGIP and will qualify as a resource adequacy resource.

The California ISO is currently working with stakeholders to reform the SGIP. It is currently proposed to combine the SGIP and LGIP which would allow small generators to qualify as providers of resource adequacy capacity.18 Should the Alpaugh North, Atwell, Corcoran, and White River projects obtain a resource adequacy qualification, their value would be similar to the Alpaugh PPA and therefore reasonable as determined above. Thus, to assure that PG&E's customers obtain the maximum value under these four PPAs, we condition Commission approval of these PPAs to require modifications to the Alpaugh North, Atwell, Corcoran, and White River PPAs. Specifically, the Alpaugh North, Atwell, Corcoran, and White River PPAs shall be modified to require the seller to pursue resource adequacy resource qualification for the projects if the Small Generator Interconnection Procedures are revised such that they may qualify as resource adequacy resources.

Therefore, given the policy preference for viable renewable capacity and the importance of developing smaller-scale renewable resources, the Alpaugh North, Atwell, Corcoran, and White River PPAs, as modified, represent a reasonable value to ratepayers and merit Commission approval.

Confidential Appendix A includes a detailed discussion of the contractual pricing terms, including PG&E's estimates of the total contract costs under the four 20 MW PPAs.

The total all-in costs of the Alpaugh North, Atwell, Corcoran, and White River PPAs are reasonable, if modified as required by this resolution, based on their relation to bids received in response to PG&E's 2008 and 2009 RPS solicitations.

Provided that PG&E modifies the PPAs to require the projects under these PPAs to pursue qualification as resource adequacy (RA) resources if Small Generator Interconnection Procedures (SGIP) are revised such that they qualify as RA resources, payments made by PG&E under the Alpaugh North, Atwell, Corcoran, and White River PPAs are fully recoverable in rates over the life of the PPAs, subject to Commission review of PG&E's administration of the PPAs.

Cost containment

The MPR is used by the Commission to assess the above-market costs of RPS contracts. There is a statutory limit on above-MPR costs which serves as a cost containment mechanism for the RPS program.19 Based on a 2013 commercial online date for the Alpaugh project, the 25-year PPA exceeds the 2009 MPR.20 The Alpaugh PPA is a long-term contract that was the result of a competitive solicitation for renewable energy and green attributes from a new project; thus it meets the eligibility criteria for Above MPR Funds (AMFs)21 established in Pub. Util. Code §399.15(d)(2).22 Based on 2012 commercial online dates for the Alpaugh North, Atwell, Corcoran, and White River projects, the 25-year PPAs exceed the 2009 MPR. These four PPAs do not meet the eligibility criteria for AMFs because they were bilaterally negotiated.

On May 28, 2009, the Director of the Energy Division notified PG&E that it had exhausted its AMFs provided by statute. Thus, PG&E is not required to procure renewable generation at above-MPR costs, but may voluntarily choose to do so. 23 PG&E is therefore voluntarily entering into the five SPS PPAs at a price that exceeds the applicable market price referent as permitted by Public Utilities Code § 399.15(d).

Procurement Review Group participation

The Procurement Review Group (PRG) was initially established in D.02-08-071 as an advisory group to review and assess the details of the utilities' overall procurement strategy, solicitations, specific proposed procurement contracts and other procurement processes prior to submitting filings to the Commission.24 PG&E states that it discussed the SPS PPAs with its PRG on August 14, 2009 and December 15, 2009.

Pursuant to D.02-08-071, PG&E's briefed its Procurement Review Group on the five SPS PPAs.

Independent Evaluator (IE) Oversaw PG&E's RPS Procurement Process

The Commission requires the use of an IE to ensure that solicitation processes are undertaken in a consistent and objective manner so that projects selected for shortlisting and resulting in executed contracts are chosen based on reasonable and consistent logic. Specifically, the IE's role is to review PG&E's bid evaluation, monitor negotiations, and review the resulting PPAs. PG&E retained Arroyo Seco Consulting (Arroyo) as the IE for PG&E's 2008 RPS solicitations. Also, as required, PG&E submitted an IE Report prepared by Arroyo with AL 3613-E.

According to the IE Report, Arroyo performed its duties overseeing the 2008 solicitation. In its IE Report, Arroyo states that it is of the opinion that PG&E's bid evaluation methodology is reasonable, PG&E conducted the solicitation in a fair and equitable manner, and contract negotiations were fair. Also, Arroyo concludes that it agrees with PG&E that the Alpaugh contract merits Commission approval based on the contract having "moderate net valuation, moderate pricing, moderate project viability, and moderate portfolio fit." While the IE finds greater uncertainty in the value of the four 20 MW SPS PPAs and estimates their value to be low to moderate versus moderate for the Alpaugh PPA, the IE also agrees with PG&E that the four 20 MW SPS contracts merit Commission approval based on their "high project viability and moderate portfolio fit."

Consistent with D.06-05-039, an independent evaluator (IE) oversaw PG&E's RPS procurement process.

DRA protests AL 3613-E

On March 9, 2010, DRA filed a protest to AL 3613-E recommending that the Commission reject AL 3613-E on three grounds: transmission and deliverability risks, performance risk, and contract form. On March 16, 2010, PG&E responded to DRA's protest recommending that the Commission deny DRA's protest on the basis that the PPAs adequately protect ratepayers from risk, comply with Commission RPS procurement rules, satisfy PG&E's portfolio need, and are competitively priced.

DRA argues that the four 20 MW PPAs should include provisions to cap the costs of network upgrades to minimize the risk of higher transmission-related costs being passed on to ratepayers. PG&E asserts that the transmission upgrade costs for the four 20 MW projects were known at the time of execution of the PPAs and are included in the project costs; thus PG&E reasons that no cost cap was or is needed. We clarify further that if in the future network upgrades are necessary for the four 20 MW projects to qualify for resource adequacy, as required by this resolution, that those unknown costs are not approved by this Resolution.

DRA also argues that there are uncertainties regarding project performance and the projects' contribution to PG&E's renewable goals. Specifically, DRA argues that the 20 MW PPAs should provide for more stringent performance provisions and adjust contract prices based on actual unit performance. As such, DRA recommends that the PPA pricing, collateral, and contractual provisions be revised for the four 20 MW PPAs. PG&E asserts that DRA's concern is misguided and that there is no minimum quantity requirement for RPS-eligibility and that the PPAs contain adequate provisions to guarantee performance and RPS eligibility. We agree with PG&E that there is no minimum generation amount for a project to be RPS-eligible.

Lastly, DRA requests more information regarding how PG&E's pro forma contract best serves ratepayer interests in delivery of energy over a long-term horizon versus other options, such as the Edison Electric Institute ("EEI") Master contract. PG&E notes that DRA has not raised any specific concerns regarding the form of the proposed PPAs. DRA's request is out of the scope of the Commission's review and approval of this advice letter and should address its concerns in the RPS proceeding.

We agree. Accordingly, we deny DRA's protest in its entirety.

RPS Eligibility and CPUC Approval

Pursuant to Pub. Util. Code § 399.13, the CEC certifies eligible renewable energy resources. Generation from a resource that is not CEC-certified cannot be used to meet RPS requirements. To ensure that only CEC-certified energy is procured under a Commission-approved RPS contract, the Commission has required standard and non-modifiable "eligibility" language in all RPS contracts. That language requires a seller to warrant that the project qualifies and is certified by the CEC as an "Eligible Renewable Energy Resource," that the project's output delivered to the buyer qualifies under the requirements of the California RPS, and that the seller uses commercially reasonable efforts to maintain eligibility should there be a change in law affecting eligibility.25

The Commission requires a standard and non-modifiable clause in all RPS contracts that requires "CPUC Approval" of a PPA to include an explicit finding that "any procurement pursuant to this Agreement is procurement from an eligible renewable energy resource for purposes of determining Buyer's compliance with any obligation that it may have to procure eligible renewable energy resources pursuant to the California Renewables Portfolio Standard (Public Utilities Code Section 399.11 et seq.), Decision 03-06-071, or other applicable law."26

Notwithstanding this language, the Commission has no jurisdiction to determine whether a project is an eligible renewable energy resource, nor can the Commission determine prior to final CEC certification of a project, that "any procurement" pursuant to a specific contract will be "procurement from an eligible renewable energy resource."

Therefore, while we include the required finding here, this finding has never been intended, and shall not be read now, to allow the generation from a non-RPS eligible resource to count towards an RPS compliance obligation. Nor shall such a finding absolve the seller of its obligation to obtain CEC certification or the utility to pursue remedies for breach of contract. Contract enforcement activities shall be reviewed pursuant to the Commission's authority to review the utilities' administration of contracts.

Confidential information

The Commission, in implementing Pub. Util. Code § 454.5(g), has determined in D.06-06-066, as modified by D.07-05-032, that certain material submitted to the Commission as confidential should be kept confidential to ensure that market sensitive data does not influence the behavior of bidders in future RPS solicitations. D.06-06-066 adopted a time limit on the confidentiality of specific terms in RPS contracts. Such information, such as price, is confidential for three years from the date the contract states that energy deliveries begin, except contracts between IOUs and their affiliates, which are public.

The confidential appendices, marked "[REDACTED]" in the public copy of this resolution, as well as the confidential portions of the advice letter, should remain confidential at this time.

COMMENTS

Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for the draft of this resolution was neither waived nor reduced. Accordingly, this draft resolution was mailed to parties for comments on October 20, 2010.

Comments were filed on November 9, 2010 by PG&E.

We carefully considered comments which focused on factual, legal, or technical errors and made appropriate changes and clarifications to the draft Resolution.

PG&E comments that it is reasonable to require SPS to pursue resource adequacy qualification for the four 20 MW projects if SPS' network upgrade costs are capped.

PG&E comments that it generally supports the draft Resolution. However, PG&E argues that the costs for network upgrades that SPS is required to incur in pursuing resource adequacy (RA) should be capped since these costs are ultimately paid by ratepayers.27 In its comments, PG&E proposes that in this instance a reasonable cost cap would be the potential RA value PG&E attributes to the projects. In this case, PG&E's proposal strikes a balance between capturing the potential RA value of the projects, limiting SPS's cost exposure, and containing ratepayer's costs. (See Confidential Appendix C for the cost cap and conditions related to the cap). We have modified the draft Resolution accordingly.

FINDINGS AND CONCLUSIONS

1. The SPS Alpaugh North, LLC, SPS Atwell Island, LLC, SPS Corcoran, LLC, and SPS White River, LLC PPAs are consistent with the bilateral contracting guidelines established in D.09-06-050.

2. The five SPS PPAs are consistent with PG&E's 2009 RPS Procurement Plan approved by D. 09-06-018.

3. PG&E evaluated the five SPS PPAs consistent with the least-cost, best-fit cost methodology identified in PG&E's 2008 RPS Procurement Plan.

4. The SPS PPAs include the current non-modifiable STCs as well as the non- non-modifiable STCs consistent with D.08-04-009, as modified by D.08-08-028.

5. The five SPS PPAs will contribute to PG&E's minimum quantity requirement established in D.07-05-028.

6. The five SPS PPAs comply with the EPS established in D.07-01-039 because the concern renewable facilities with capacity factors less than 60 percent.

7. PG&E asserts that the five SPS projects are viable and will provide renewable energy according to the terms and conditions in the PPAs.

8. The total all-in costs of the SPS Alpaugh, LLC PPA are reasonable based on its relation to bids received in response to PG&E's 2008 and 2009 RPS solicitations.

9. Payments made by PG&E under the SPS Alpaugh, LLC PPA are fully recoverable in rates over the life of the PPA, subject to Commission review of PG&E's administration of the PPA.

10. The Alpaugh North, Atwell, Corcoran, and White River PPAs shall be modified to require the seller to pursue resource adequacy resource qualification for the projects if the Small Generator Interconnection Procedures are revised such that they may qualify as RA resources.

11. PG&E submitted comments proposing modifications to the draft Resolution to integrate the conditions into the Alpaugh North, Atwell, Corcoran, and White River PPAs as set forth by ordering paragraph two of this Resolution.

12. The total all-in costs of the SPS Alpaugh North, LLC, SPS Atwell Island, LLC, SPS Corcoran, LLC, and SPS White River, LLC PPAs are reasonable, if modified as required by this Resolution, based on their relation to bids received in response to PG&E's 2008 and 2009 RPS solicitations.

13. Provided that PG&E modifies the Alpaugh North, Atwell, Corcoran, and White River PPAs to require the projects under these PPAs to pursue qualification as resource adequacy (RA) resources if Small Generator Interconnection Procedures (SGIP) are revised such that they qualify as RA resources, payments made by PG&E under the Alpaugh North, Atwell, Corcoran, and White River PPAs are fully recoverable in rates over the life of the PPAs, subject to Commission review of PG&E's administration of the PPAs.

14. Based on a 2013 commercial online date for the Alpaugh project, the 25-year PPA exceeds the 2009 MPR.

15. Based on a 2012 commercial online date for the Alpaugh North, Atwell, Corcoran, and White River projects, the 25-year PPAs exceed the 2009 MPR.

16. PG&E is voluntarily entering into the five SPS PPAs at prices that exceed the applicable market price referent as permitted by Public Utilities Code §399.15(d).

17. Pursuant to D.02-08-071, PG&E's briefed its Procurement Review Group on the five SPS PPAs.

18. Consistent with D.06-05-039, an independent evaluator oversaw PG&E's procurement process.

19. The Division of Ratepayer Advocates' protest of AL 3613-E is denied in its entirety.

20. Procurement pursuant to the five SPS PPAs is procurement from eligible renewable energy resources for purposes of determining PG&E's compliance with any obligation that it may have to procure eligible renewable energy resources pursuant to the California Renewables Portfolio Standard (Public Utilities Code Section 399.11 et seq.), D.03-06-071 and D.06-10-050, or other applicable law.

21. The immediately preceding finding shall not be read to allow generation from a non-RPS-eligible-renewable energy resource under these PPAs to count towards an RPS compliance obligation. Nor shall that finding absolve PG&E of its obligation to enforce compliance with these PPAs.

22. The confidential appendices, marked "[REDACTED]" in the public copy of this resolution, as well as the confidential portions of the advice letter, should remain confidential at this time.

23. The SPS Alpaugh, LLC PPA proposed in AL 3613-E should be approved effective today without modification.

24. The SPS Alpaugh North, LLC, SPS Atwell Island, LLC, SPS Corcoran, LLC, and SPS White River, LLC PPAs proposed in AL 3613-E should be approved effective today with modification.

THEREFORE IT IS ORDERED THAT:

This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on November 19, 2010; the following Commissioners voting favorably thereon:

MICHAEL R. PEEVEY

President

DIAN M. GRUENEICH

JOHN A. BOHN

TIMOTHY ALAN SIMON

NANCY E. RYAN

Commissioners

Confidential Appendix A

Contract Summary

[Redacted]

Confidential Appendix B

Excerpt from Confidential IE Report28

[Redacted]

Confidential Appendix C

Required Modifications to the Alpaugh North, Atwell, Corcoran, and White River PPAs

[Redacted]

1 SB 1078 (Sher, Chapter 516, Statutes of 2002); SB 107 (Simitian, Chapter 464, Statutes of 2006); SB 1036 (Perata, Chapter 685, Statutes of 2007).

2 All further references to sections refer to Public Utilities (Pub. Util.) Code unless otherwise specified.

3 See, Pub. Util. Code § 399.15(b)(1).

4 The current process set forth for seeking Commission approval for an RPS contract is that RPS contracts, of any length greater than one month in duration, must be submitted for approval by advice letter, unless special conditions warrant filing an application (for example, if the PPA does not include the required standard terms and conditions).

5 See, e.g., Resolution E-4350.

6 See D.10-04-052

7 See Pub. Utils. Code §399.14.

8 In AL 3613-E, PG&E compared the SPS PPAs to its 2008 RPS Procurement Plan and evaluated the projects usings its 2008 LCBF methodology. For its project viability assessment, though, PG&E included a comparison of the PPAs to its 2009 RPS solicitation.

9 PG&E's 2009 Plan was approved by D.09-06-018 on June 8, 2009. D.09-06-018 is available at: http://docs.cpuc.ca.gov/published/FINAL_DECISION/102099.htm.

10 See §399.14(a)(3).

11 See §399.14(a)(2)(B)

12 For purposes of D.07-05-028, contracts of less than 10 years duration are considered "short-term," and facilities that commenced commercial operations on or after January 1, 2005 are considered "new."

13 "Baseload generation" is electricity generation at a power plant "designed and intended to provide electricity at an annualized plant capacity factor of at least 60%." Pub. Utils. Code § 8340 (a).

14 Pacific Gas And Electric Company Bilateral Contract Evaluation: Advice Letter Report of the Independent Evaluator on Five Proposed Contracts with Five Project Susbidiaries of Solar Partners Solutions, LLC (February 3, 2010), as submitted in AL 3613-E, page I-55

15 Porterville Recorder: http://www.recorderonline.com/news/solar-46606-south-county.html, accessed 10/13/2010

16 As stated above, PG&E's 2009 RPS solicitation was complete at the time of the SPS' PPAs execution and filing of AL 3613-E.

17 Pacific Gas And Electric Company Bilateral Contract Evaluation: Advice Letter Report of the Independent Evaluator on Five Proposed Contracts with Five Project Susbidiaries of Solar Partners Solutions, LLC (February 3, 2010), as submitted in AL 3613-E, page I-56

18 California ISO: Small and Large Generator Interconnection Procedures: http://www.caiso.com/275e/275ed48c685e0.html

19 See Pub. Utils. Code §399.15.

20 See Resolution E-4298.

21 The $/MWh portion of the contract price that exceeds the MPR, multiplied by the expected generation throughout the contract term, represents the total AMFs for a given PPA.

22 The following eligibility criteria for AMFs: (1) contract was selected through a competitive solicitation, (2) contract covers a duration of no less than 10 year, (3) contracted project is a new facility that will commence commercial operations after January 1, 2005, (4) contract is not for renewable energy credits, and (5) the above-market costs of a contract do not include any indirect expenses including imbalance energy charges, sale of excess energy, decreased generation from existing resources, or transmission upgrades.

23 On May 28, 2009, the Director of the Energy Division notified PG&E that it had exhausted its AMFs account.

24 The PRG for PG&E includes representatives of the California Department of Water Resources, the Commission's Energy Division and Division of Ratepayer Advocates, Union of Concerned Scientists, The Utility Reform Network, the California Utility Employees, and Jan Reid, as a PG&E ratepayer.

25 See, e.g. D. 08-04-009 at Appendix A, STC 6, Eligibility.

26 See, e.g. D. 08-04-009 at Appendix A, STC 1, CPUC Approval.

27 Customarily and pursuant to FERC-approved CAISO tariffs, the generation developer interconnecting as a full capacity deliverable resource pays the relevant Participating Transmission Owner for transmission network upgrades and is repaid, with interest, over a five year period commencing with commercial operation, through the transmission access charge (TAC). (See § 11.4.1 of Standard Large Generator Interconnection Agreement (LGIA)

http://www.caiso.com/1b93/1b9388ec11d10.pdf)

28 Confidential Appendix to the Advice Letter Report of the Independent Evaluator on Five Proposed Contracts with Subsidiaries of Solar Partners Solutions, LLC Pages C-4 - C-25.

Top Of Page