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PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ID #8992

ENERGY DIVISION RESOLUTION E-4291

Redacted

RESOLUTION

Resolution E-4291. Pacific Gas and Electric (PG&E) requests approval of two renewable power purchase agreements with Shell Energy North America (US), L.P.

PROPOSED OUTCOME: This Resolution approves cost recovery for two PG&E short-term renewable energy power purchase agreements (PPAs) with Shell Energy North America (US), L.P. The PPAs and associated hedging strategy are approved without modification, contingent upon a compliance filing.

ESTIMATED COST: Costs of this contract are confidential at this time

By Advice Letter 3477-E filed on June 17, 2009.

__________________________________________________________

SUMMARY

PG&E's proposed PPAs with Shell Energy North America (US), L.P. comply with the Renewables Portfolio Standard (RPS) procurement guidelines and are approved contingent upon a PG&E compliance filing demonstrating that the hedging strategy produces prices substantially similar to the most recent PG&E estimates.

PG&E filed Advice Letter (AL) 3477-E on June 17, 2009 requesting Commission review and approval of two renewable energy PPAs executed with Shell Energy North America (US), L.P. (Shell) and an associated hedging strategy which does not involve Shell. The PPAs are short-term, bilateral contracts for a portion of the generation from two operating wind facilities. The first PPA (White Creek) is for three years. The second PPA (Big Horn) is for a term of two years. Both of the wind facilities associated with the PPAs began operating after January 1, 2005, have been certified by the California Energy Commission (CEC) as RPS-eligible facilities, and are located in the state of Washington.

The following tables summarize the two agreements:

White Creek Agreement

Generating Facility

Technology Type

Term

(Years)

Minimum Capacity

(MW)

Minimum Energy

(GWh)

Contract Delivery

Start

Date

Location

White Creek

Wind, operating

3

204.7

53

7/1/2009

Roosevelt, Washington

Big Horn Agreement

Generating Facility

Technology Type

Term

(Years)

Minimum Capacity

(MW)

Minimum Energy

(GWh)

Contract Delivery

Start

Date

Location

Big Horn

Wind, operating

2

200

75

7/1/2009

Bickleton, Washington

NOTICE

Notice of AL 3477-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

Advice Letter 3477-E was not protested.

DISCUSSION

Overview of RPS Program

The RPS Program administered by the Commission requires each utility to increase its total procurement of eligible renewable energy resources by at least 1% of retail sales per year so that 20% of the utility's retail sales are procured from eligible renewable energy resources no later than December 31, 2010.1

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.

PG&E requests approval of two renewable energy contracts with Shell and an associated "hedging strategy"

On June 17, 2009, PG&E filed AL 3477-E requesting Commission approval of two renewable power procurement agreements with Shell, which were negotiated bilaterally. As part of managing these two PPAs, PG&E also requests approval of a "hedging strategy." PG&E explains that the hedging strategy has two components. The first component is discussed in Confidential Appendix D of PG&E's Advice Letter 3477-E. Under the second component of the Hedging Strategy, PG&E will make forward purchases at a CAISO import point, most likely COB, to fix the price of import energy and provide incremental import energy into California. Within 60 days of CPUC Approval of the Agreements and Hedging Strategy, PG&E expects to implement the Hedging Strategy through a competitive process, with the selected products balancing maximum liquidity and overall energy portfolio needs. Other benefits associated with the Hedging Strategy are discussed in Confidential Appendix D of PG&E's Advice Letter.

The White Creek Agreement provides that PG&E will procure RPS-eligible energy generated at the White Creek Wind I facility located in the state of Washington. The facility began operating in 2007 and is certified by the CEC as a RPS-eligible facility. The Big Horn Agreement provides that PG&E will procure RPS-eligible energy generated at the Big Horn wind facility also located in Washington. The facility began operating in 2006 and is certified by the CEC as a RPS-eligible facility.

PG&E began accepting deliveries from Shell under both the White Creek and Big Horn Agreements on July 1, 2009. Pursuant to the Agreements, PG&E will pay Shell a one-time true-up settlement payment for the Green Attributes generated prior to Commission approval.

Procurement from Shell is expected to contribute a minimum of 53 and 75 gigawatt-hours (GWh) annually towards PG&E's Annual Procurement Target (APT).

PG&E requests the Commission to issue a resolution that:

Energy Division Review Of the Proposed PPAs

Energy Division evaluated the PPAs for the following criteria:

Consistency with PG&E's 2008 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.2 The Commission reviews the results to verify that the utility conducted its solicitation according to its Commission-approved procurement plan. PG&E's 2008 RPS Procurement Plan (Plan) was approved by D.08-02-008 on February 14, 2008. Pursuant to statute, PG&E's 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.3

The PPAs are consistent with PG&E's 2008 RPS Procurement Plan, approved by D.08-02-008.

Consistency with the Resource Needs Identified In PG&E's Plan

PG&E states that the generation from the PPAs will meet the resource needs identified in its Plan. In its Plan, PG&E's goal was to procure approximately 800 to 1,600 GWh per year. PG&E's Plan also noted that near-term deliveries were more valuable to PG&E. Combined, the facilities will annually deliver 128 GWhs to PG&E. These deliveries from the facilities will contribute to PG&E's 20 percent goal under the current flexible compliance rules.

The PPAs are consistent with the resource needs identified in PG&E's 2008 Procurement Plan.

Consistency with RPS Standard Terms and Conditions (STCs)

The proposed PPAs are comprised of the Edison Electric Institute (EEI) Master Power Purchase Agreement and a Confirmation Letter which conforms to the Commission's decisions requiring STCs for RPS contracts.

The PPAs include the Commission adopted RPS standard terms and conditions, including those deemed "non-modifiable".

Consistency with Bilateral Contracting Guidelines

In D.09-06-050 the Commission determined that bilateral contracts should be reviewed according to the same processes and standards as contracts that come through a solicitation. However, AL 3477-E was submitted before that decision was effective. Thus, Energy Division conducted its review of the PPAs based on the four requirements identified in D.06-10-019.

The PPAs are consistent with the bilateral contracting guidelines established in D.06-10-019.

Consistency with RPS Delivery Rules

Where an advice letter requests Commission approval of a PPA with a facility that does not have its first point of connection with the California transmission network and deliver electricity to an in-state location, the CEC provides a written determination to the Commission addressing whether the proposed delivery structure meets the RPS delivery requirements set forth in the CEC's RPS Eligibility Guidebook.8

Appendix A to this resolution contains a letter from CEC Staff determining that the delivery structure contained in the proposed PPAs meets the CEC's RPS delivery requirements as set forth in the CEC's RPS Eligibility Guidebook.

Project Viability

PG&E asserts that there are no viability concerns with the Agreements because the White Creek and Big Horn facilities are already operating and PG&E expects that Shell will be able to perform all of its financial and other obligations under the agreement.

There is no project viability risk associated with the Shell PPAs because the facilities are online and generating electricity.

Compliance with the Minimum Quantity Condition

D.07-05-028 established a "minimum quantity" condition on the ability of utilities to count an eligible contract of less than 10 years duration with a facility that commenced commercial operations prior to January 1, 2005 for compliance with the RPS program.9 In the calendar year that a short-term contract with an existing facility is executed, the utility must also enter into long-term contracts with new facilities equivalent to at least 0.25% of the utility's previous year's retail sales.

The facilities that are to deliver energy pursuant to the PPAs began commercial operation after January 1, 2005. Thus, the minimum quantity condition does not apply.

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 powerplant. The EPS applies to all energy contracts for baseload generation that are at least five years in duration.10 Renewable energy contracts are deemed compliant with the EPS except in cases where intermittent renewable energy is firmed and shaped with generation from non-renewable resources.

The PPAs are not long-term financial commitments subject to the EPS because the terms of both PPAs are less than five years.

Procurement Review Group (PRG) Concerns

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

PG&E informed the PRG of the proposed transactions on March 23, 2009 and May 15, 2009.

Pursuant to D.02-08-071, PG&E's Procurement Review Group (PRG) participated in the review of the PPAs. The PRG feedback, as described in the confidential information provided with the AL, did not provide a basis for disapproval of the PPAs.

Although Energy Division is a member of the PRG, it reserved judgment on the contract and associated hedging strategy until the AL was filed. Energy Division reviewed the transaction independently of the PRG, and allowed for a full protest period before concluding its analysis.

Comparison to the Results of PG&E's 2008 Solicitation

Although the PPAs were negotiated bilaterally, PG&E conducted a least-cost, best-fit (LCBF) bid evaluation of the PPAs to compare them to their 2008 solicitation bids. 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 and integration costs; 3) evaluation of portfolio fit; and 4) consideration of non-price factors. 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, a LCBF evaluation was conducted for the bilaterally negotiated PPAs in order to evaluate their value relative to all of PG&E's other RPS options.

PG&E determined that the PPAs are favorable relative to proposals received in response to PG&E's 2008 solicitation because the PPAs' market valuations compare favorably with bids from its 2008 solicitation. The PPAs also have value to PG&E's ratepayers relative to bids received in their 2008 solicitation because the facilities can deliver in the near-term.

The PPAs compare favorably to the results of PG&E's 2008 solicitation.

Cost Reasonableness

Confidential Appendix B includes a detailed discussion of the contractual pricing terms, including PG&E estimates of the total contract costs under the PPAs and hedging strategy.

The total expected costs of the PPAs and hedging strategy, as estimated by PG&E, are reasonable based on their relation to bids received in response to PG&E's 2008 solicitation.

Provided the generation is from an eligible renewable energy resource, payments made by PG&E under the PPAs and hedging strategy are fully recoverable in rates over the life of the PPAs, subject to Commission review of PG&E's administration of the PPAs.

In order to ensure that the actual costs of the PPAs and hedging strategy are consistent with the expected costs, final Commission approval shall be contingent upon a PG&E Tier 1 Advice Letter compliance filing submitted 30 days after execution of the hedging strategy documenting the fixed price PG&E obtained and demonstrating that the executed hedging strategy produced prices substantially similar to the most recent PG&E estimates provided to Energy Division Staff.

Ratepayer Impacts of Procurement Prior To Commission Approval Of The PPAs

PG&E began procuring energy under the both the White Creek and Big Horn Agreements on July 1, 2009, prior to obtaining Commission approval of the PPAs. Pursuant to the Agreements, PG&E will pay Shell a one-time true-up settlement payment for the Green Attributes generated prior to Commission approval.

In general, CPUC approval is required for generation under a PPA to be used for RPS compliance. PG&E accordingly placed itself at risk by incurring costs under the PPAs before Commission approval was obtained, as the Commission could potentially deny or condition approval of the PPAs.

In this instance, PG&E discussed the PPAs with its PRG, the PPAs otherwise comply with Commission decisions, and we have determined that the price is reasonable. Therefore, there is no harm to ratepayers from PG&E's failure to submit the contract for approval in a timely manner. However, approval of these PPAs, notwithstanding the deliveries prior to Commission approval, is not precedential, and does not constitute any change in standard Commission procedures or practices.

RPS ELIGIBILITY AND CPUC APPROVAL

Pursuant to Pub. Utils. 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. A resource's eligibility under the RPS program, as determined by the CEC, may change over time. Moreover, it is unlikely that a resource that is not yet operational will have CEC certification. 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 use commercially reasonable efforts to maintain eligibility should there be a change in law affecting eligibility.11

Notwithstanding the possible changing nature of a resource's RPS eligibility over time, 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."12

Clearly, the Commission cannot determine now that "any procurement" in the future 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 any contracting party of its obligation to obtain CEC certification and/or to pursue remedies for breach of contract to ensure that only RPS-eligible generation is delivered and paid for under a Commission-approved contract. Such contract enforcement activities shall be reviewed pursuant to the Commission's authority to review the administration of such contracts.

CONFIDENTIAL INFORMATION

The Commission, in implementing Pub. Utils. 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 ON THIS RESOLUTION

Pub. Utils. Code § 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, and will be placed on the Commission's agenda no earlier than 30 days from today.

FINDINGS AND CONCLUSIONS

1. The PPAs are consistent with PG&E's 2008 RPS Procurement Plan, approved by D.08-02-008.

2. The PPAs are consistent with the resource needs identified in PG&E's 2008 Procurement Plan.

3. The PPAs include the Commission-adopted RPS standard terms and conditions including those deemed "non-modifiable".

4. The PPAs are consistent with the bilateral contracting guidelines established in D.06-10-019.

5. Appendix A to this resolution contains a letter from CEC Staff determining that the delivery structure contained in the proposed PPAs meets the CEC's RPS delivery requirements as set forth in the CEC's RPS Eligibility Guidebook.

6. There is no project viability risk associated with the Shell PPAs because the facilities are online and generating electricity.

7. The facilities that are to deliver energy pursuant to the PPAs began commercial operation after January 1, 2005. Thus, the minimum quantity condition does not apply.

8. The PPAs are not long-term financial commitments subject to the EPS because the terms of both PPAs are less than five years.

9. Pursuant to D.02-08-071, PG&E's Procurement Review Group (PRG) participated in the review of the PPAs.

10. The PRG feedback, as described in the confidential information provided with the advice letter, did not provide a basis for disapproval of the PPAs.

11. The PPAs compare favorably to the results of PG&E's 2008 solicitation

12. The total expected costs of the PPAs and hedging strategy, as estimated by PG&E, are reasonable based on their relation to bids received in response to PG&E's 2008 solicitation.

13. Provided the generation is from an eligible renewable energy resource, payments made by PG&E under the PPAs and hedging strategy are fully recoverable in rates over the life of the PPAs, subject to Commission review of PG&E's administration of the PPAs.

14. In order to ensure that the actual costs of the PPAs and hedging strategy are consistent with the expected costs, final Commission approval shall be contingent upon a PG&E Tier 1 Advice Letter compliance filing submitted 30 days after execution of the hedging strategy documenting the fixed price PG&E obtained and demonstrating that the executed hedging strategy produced prices substantially similar to the most recent PG&E estimates provided to Energy Division Staff.

15. There is no harm to ratepayers from PG&E's failure to submit the PPAs for approval in a timely manner.

16. Approval of these PPAs, notwithstanding the deliveries prior to Commission approval, is not precedential and does not constitute any change in standard Commission procedures or practices.

17. Approval of the PPAs and the associated hedging strategy does not constitute a precedent for future renewable procurement contract price structures.

18. Procurement pursuant to the 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.

19. 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 Standard Term and Condition 6, set forth in Appendix A of D.08-04-009, and included in these PPAs.

20. 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.

21. AL 3477-E should be approved effective today.

THEREFORE IT IS ORDERED THAT:

1. Pacific Gas and Electric Company's Advice Letter 3477-E, requesting Commission review and approval of power purchase agreements with Shell Energy North America (US), L.P., is approved without modification.

2. PG&E shall submit a Tier 1 Advice Letter compliance filing no later than 30 days after execution of the hedging strategy documenting the fixed price PG&E obtained and demonstrating that the executed hedging strategy produced prices substantially similar to the most recent PG&E estimates provided to Energy Division Staff.

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 December 3, 2009; the following Commissioners voting favorably thereon:

Appendix A

CEC Letter Regarding Eligibility of Shell PPAs' Proposed Delivery Structures

Confidential Appendix B

Contract Summary

[REDACTED]

1 See Pub. Utils. Code § 399.15(b)(1).

2 Pub. Utils. Code, Section §399.14.

3 Pub. Utils. Code, Section §399.14(a)(3).

4 The PPA is ineligible for the cost limitation because it did not result from a competitive solicitation. Pub. Utils. Code §399.15(d)(2).

5 "For now, utilities' bilateral RPS contracts, of any length, must be submitted for approval by advice letter." D.06-10-019 at 31.

6 "All RPS-obligated LSEs are also free to enter into bilateral contracts of any length with RPS-eligible generators, as long as the contracts are at least one month in duration, to enable the CEC to verify RPS procurement claims." D.06-10-019 at 29.

7 The contract price of bilaterals must be deemed reasonable by the Commission. D.06-10-019, at 31.

8 Renewables Portfolio Standard Eligibility Guidebook, 3rd Edition, publication # CEC-300-2007-006-ED3-CMF (January 2008), available at http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-ED3-CMF.PDF

9 For purposes of D.07-05-028, contracts of less than 10 years duration are considered "short-term" contracts and facilities that commenced commercial operations prior to January 1, 2005 are considered "existing".

10 "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).

11 See, e.g. D. 80-04-009 at Appendix A, STC 6, Eligibility.

12 See, e.g. D. 80-04-009 at Appendix A, STC 1, CPUC Approval.

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