DISCUSSION
Energy Division has reviewed the advice letter. The Amended and Restated PPA will allow PG&E to (1) dispatch the Fresno Project when the power is needed and economical for PG&E, resulting in lower power procurement costs; and (2) obligate the Santa Maria project to provide to back up generation for the Fresno project until local transmission constraints are removed (work for which is now under way and is scheduled for completion by November 2006), and (3) terminate the Santa Maria Cogen, Inc. PPA.
PG&E has complied with the RALF requirements
The restructuring advice letter shall contain the following categories of information ("a" through "h") shown below, including all relevant work papers and other relevant supporting documents, per Section 3 of the RALF procedure.6
a. Identification of the QF[s], location of the QF[s`] generating facility, brief description of the generating facility size, type of technology and other pertinent or unique characteristics.
Originally, the Fresno Cogen Project was a nominally rated 26 MW natural gas-fired combined-cycle cogeneration plant supplying process steam to its thermal host which dries agricultural products. The primary energy cycle was powered by a refurbished FT4 natural gas turbine generator set and waste heat was supplied to a Heat Recovery Steam Generator (HRSG) which in turn powers a steam turbine. However, in December of 2004, Fresno completed a repower of the facility as required by a previous contract amendment and is now nominally rated at 50 MW. The Fresno Project is located at 8105 B South Lassen Avenue, San Joaquin, California. However, under the proposed contract restructuring, only 33 MW will be under contract to PG&E.
The Santa Maria Project is an 8 MW simple cycle gas-fired power plant with one "Mars 90" gas turbine generator as the prime mover. The unfired HRSG coupled to the exhaust of the gas turbine is strictly for process steam production used to make ice. The Santa Maria Project is located at 802 South Hanson Way, Santa Maria, California.
b. Ownership of the QF project[s] and related companies, including affiliate relationships of the parties involved in the transaction, if any.
The Fresno Project is owned by a limited partnership known as Fresno Cogeneration Partners, LP ("FCPLP"), a California limited partnership, with Fresno Cogen Inc. as its general partner. FCPLP acquired the Fresno project in 1994 from a subsidiary of Northwest Natural Gas. Harold E. Dittmer (HED) owns a majority beneficial interest in FCPLP. FERC originally certified the Fresno Project as a QF on January 26, 1988 (FERC docket number QF88-134-001). At that time the Fresno Project was entirely owned by a subsidiary of Northwest Natural Gas and had no electric utility ownership. Since 1994, it has been owned by Fresno Cogeneration Partners, LP. Since the time of its original FERC certification, the Fresno Project has been recertified once to reflect an ownership change. PG&E Corporation and its affiliate, Pacific Gas and Electric Company, are not affiliated in any way with any of the foregoing companies.
The Santa Maria Project was developed by Santa Maria Associates, LTD with Bonneville Pacific Corporation as its general partner. FERC originally certified the Santa Maria Project as a QF on February 11, 1986 (FERC docket number QF85- 644-000). In December 1994, Santa Maria Associates, LTD sold all of its rights and interest in the project to Santa Maria Cogen, Inc., the current owner. HED owns a majority beneficial interest in the Santa Maria Cogen Inc., or "Santa Maria." Since the time of its original FERC certification, Santa Maria has been recertified five times to reflect a combination of ownership changes, configuration changes, and the addition of an ice making facility. PG&E Corporation and its affiliate, Pacific Gas and Electric Company, are not affiliated in any way with any of the foregoing companies.
c. A detailed description of the historical operational performance of the project[s], including historical production and compliance with performance and efficiency monitoring standards.
The Fresno Project was the subject of a dispute over compliance with FERC-mandated operating and efficiency standards for the 1989 - 1991 operating years. As discussed in AL 2872-E, previous contract amendments resolved all disputes relating to compliance with operating and efficiency standards. PG&E has not taken any issue with Fresno's operating and efficiency standards since the current owner purchased the Fresno Project in 1994.
The Santa Maria Project has never had an issue related to compliance with FERC-mandated operating and efficiency standards. Every compliance check of Santa Maria that PG&E has conducted has demonstrated that the Santa Maria Project is in full compliance with all requirements related to operating and efficiency standards. Prospectively, the past performance of the Santa Maria Project is a moot point, since it will no longer be under contract to PG&E.
d. A summary of the proposed contract restructuring.
PG&E requests Commission approval to modify two existing PPAs totaling 33 MW. The Santa Maria PPA (for 8 MW) would first be assigned to Fresno, then terminated (although Santa Maria would remain obligated to be available for dispatch until some local transmission constraints affecting Fresno are removed). The Fresno PPA would be restructured. The restructured PPA will provide for the purchase of 33 MW of energy and firm capacity from Fresno (an increase of 8 MW from the current 25 MW) for a term commensurate with that of the remaining terms of the existing Fresno and Santa Maria PPAs. Fresno's PPA will otherwise expire on March 25, 2020, and Santa Maria's on September 10, 2019, while the proposed restructured PPA would expire on February 10, 2020.
The Amended and Restated PPA would also change energy payments to reflect Fresno's actual variable costs and provide PG&E a firm capacity payment discount and daily dispatch rights. In return, Fresno's owners receive energy payments that cover their variable operating costs and would no longer be required to maintain QF status.
e. A summary of the ratepayer benefits.
Ratepayers will benefit from the proposed contract restructuring through (1) the replacement of the must-take power obligation with an option for PG&E to dispatch the Fresno facility when Fresno's power is needed and is more economic than other alternatives, and (2) the reduction of the contract capacity payment.
Under the current PPA, the Fresno Project can operate to maximize its profit by operating as a baseload resource (24 hours per day, 7 days per week) when energy prices exceed its variable operating costs. When energy prices are less than operating costs, the Fresno project can limit operations to a 13-hours per day, 5 days per week basis (excluding holidays), providing peak electrical generation to PG&E's local 60 kV transmission system. Under the Amended and Restated PPA, PG&E states that dispatch rights of the Fresno project will add significant ratepayer benefit when compared to the must-take obligations of the existing PPAs. Reduced contract capacity payments will add additional value. Energy Division agrees that the reduced contract capacity payments will add additional value. PG&E's demonstration in AL 2872-E of the present value benefit attributable to the reduced capacity payments is acceptable.
However, Energy Division considers PG&E's modeling of the proposed energy benefits of the PPA restructuring to be over-valued, for purposes of calculating a shareholder incentive award. As stated in the advice letter, PG&E quantified the present value benefits of the contract restructuring "using a `spark-spread' option model, which is a transformed variant of the Black option valuation model" (AL 2872-E, p.11).7 This type of model creates a series of probabilistic outcomes or benefits. The probability that these benefits will all materialize exactly as modeled is extremely uncertain, yet PG&E has proposed to calculate the shareholder incentive based upon 10% of this project amount. We are not inclined to base a specific, deterministic shareholder incentive award on the uncertain, probabilistic calculations as submitted.
Instead, Energy Division recommends that the net ratepayer benefit of the energy portion of the contract restructuring be determined using a more traditional, deterministic approach, based on a comparison of heat rates. The existing heat rate for this contract is PG&E's short-run avoided cost (SRAC) heat rate. The new heat rate is the proposed, contractually specified heat rate, which is confidential. The operational energy cost difference between the two contracts, at comparable levels of operation and gas prices, represents a reasonable estimate of the net ratepayer benefit of the energy portion of the contract restructuring, rather than that proposed in the advice letter. Under this approach, the net ratepayer benefit of the energy portion of the contract restructuring would still be positive, but would represent (1) a more reasonable estimate of the expected net energy benefits that might actual materialize as a result of the contract restructuring, and (2) a significantly reduced amount relative to that calculated in the advice letter.
As noted above, Energy Division agrees with the capacity payment benefits as submitted, but estimates lower energy benefits. As calculated by Energy Division, the total net ratepayer benefits, including net energy and capacity benefits, are 48.6% of the amount submitted in the advice letter. Thus, the total requested shareholder incentive award should be reduced to 48.6% of the amount requested in AL 2872-E.
f. A description of any significant, pending legal or regulatory disputes between the Utility and the QF, and their resolution or status.
There are no current or anticipated legal or regulatory disputes between the parties to this proposed PPA restructuring.
g. An assessment of the QF's projected economic and operational viability under the existing contract.
The Projects are both economically viable. PG&E projects positive income from their operation every year to the end of each PPA. PG&E concludes that the Projects are well maintained by examining their operating records over the past more than 15 years. Both projects have long-established records of making reliable firm capacity deliveries under their respective PPAs, and the projects have never been placed on probation under their current ownership.
h. A detailed description of ratepayer benefits, shareholder incentive, and sensitivity analyses.
Ratepayer Benefits. The Amended PPA has several benefits: the replacement of a must-take contract with a dispatchable contract; reduced heat rate relative to current SRAC; and reduced capacity payments.
Shareholder Incentive. The Amended PPA will terminate in 2020 and the aforementioned benefits will accrue over the intervening time period. Under the RALF process, the utility is eligible for a shareholder incentive reward for accomplishing the contract restructuring. To determine that amount, PG&E first calculated the present value of the benefits of the restructured contract as compared with a forecast of SRAC energy payments and contract capacity payments based on the expected future operation of the facility. Second, PG&E calculated 10% of that present value benefit amount as the shareholder reward. As stated above, Energy Division accepts the net ratepayer benefit valuation associated with the reduced capacity payments, but considers PG&E's modeling of the proposed energy benefits of the PPA restructuring to be over-valued, for purposes of calculating a shareholder incentive award. Energy Division proposes to calculate the energy benefits as modeled as a comparison of heat rates at comparable gas prices. As noted above, the total net ratepayer benefits, including net energy and capacity benefits, are 48.6% of the amount submitted in the advice letter. Thus, the total requested shareholder incentive award should be reduced to 48.6% of the amount requested in AL 2872-E.
i. A copy of the QF's existing contract, including any amendments.
This information is attached to AL 2872-E as Appendix H, "Original Power Purchase Agreements, including all prior amendments and agreements executed at least three years prior."
j. A copy of the executed or unexecuted restructured agreement for which approval is sought and copies of all related agreements between the QF and the Utility.
This information is attached to AL 2872-E as Appendix A, "Amended Power Purchase Agreement including all prior amendments and agreements executed within the last three years."
DRA supports the contract restructuring
The RALF procedure requires that a statement of support or neutrality from DRA be attached to any restructuring Advice Letter filing. On August 1, 2006, DRA issued a letter in support for the contract restructuring, which is attached to AL 2872-E as Partially Redacted Appendix D - DRA Letter of Support. The DRA Letter of Support reflects the advice letter as filed. Upon review, Energy Division agrees that this is a beneficial contract restructuring; however, Energy Division recommends a reduction in the shareholder incentive amount as previous described.
6 The RALF requirements are reproduced here as Attachment 1 to E-3898, a modified version of Attachment B to D.98-12-066, which reflect determinations made in D.98-12-066.
7 The spark-spread is the difference between the market price of power at NP15, for example, and the cost of producing electricity from a generator.
