VI. Comments on Draft Decision

Pursuant to Section 311(g)(2) of the Public Utilities Code, this decision must be served on all parties and subject to at least 30-day 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 the parties in the proceeding.

At the PHC held on May 5, 2004, the parties stipulated to shorten the comment period. On May 17, 2004, this decision was circulated for public review and comment. On May 28, 2004, ten parties filed opening comments: CalWEA, CEERT, GPI, ORA, PG&E, SCE, Solargenix, SDG&E, TURN and Vulcan Power Company (Vulcan). On June 4, 2004, five parties filed reply comments: CEERT, ORA, PG&E, SCE, and SDG&E.

In opening comments on the draft decision, a majority of the parties fundamentally supported the draft decision. Parties primarily addressed various modeling,²² process,²³ and gas forecasting issues.²⁴

Modeling (Capital Structure). This issue generated some interesting discussion in comments, and while we do not change our fundamental approach, we will clarify it.

CalWEA does not object to the 70/30 debt/equity ratio in the draft decision, which it considers to be "typical of a merchant" plant, bu CalWEA contends that the use of utility-type capital structure (e.g., 52/48) is more internally consistent and easier to use, and should be adopted. CEERT contends that capital structure is an input value and, as such, should not be adopted in the MPR methodology decision. GPI notes that the draft decision correctly adopts an independent power plant ownership structure, but additionally recommends the use of a "fully loaded capital cost" for the proxy plant. PG&E states that the "cost of debt and equity for the proxy plant should reflect the costs of an independent power producer that has a long-term contract with a creditworthy utility." However, PG&E recommends the addition of clarifying language to reflect the fact that a current (e.g., 2004) cost of capital will be used to calculate MPRs, rather than the November 2001 assumptions referred to in the draft decision. SCE contends that capital structure should, more appropriately, be governed by debt service coverage ratios (the ratio of Operating Income to Debt) that a project will support, rather than simply prescribed without such consideration. SCE notes that in the SCE MPR model (Version Final6a.xls), an 80/20 mix produces an average debt coverage ratio of 1.37. We appreciate SCE's comments on debt coverage ratios. On this point, we note that a 70/30 mix in the same model produces an average debt coverage ratio of 1.56 as calculated the fixed component portion of the model.²⁵ Based on party comments, we conclude that it is in fact appropriate to use an independent power producer ownership structure, and that current market data should be used to calculate MPRs.

Modeling (Capital Recovery). CalWEA supports capital recovery (for debt and equity) over a 20-year term, and notes that the draft decision mischaracterized CalWEA's position on this issue. On the other hand, CEERT recommends equity recovery over 20 years, and debt recovery over the contract term (10, 15, or 20 years) depending upon the bid. SCE states that both debt and equity recovery should occur over a full 20-year term, regardless of the contract term proposed by the bidder. PG&E agrees as well. Based on the record before us now, we agree with CalWEA and SCE on this point, and clarify that capital recovery for both debt and equity is over a 20-year term.

Modeling (MPR Description). SCE correctly notes that there is no "cost component for rate of return on operating income" in the variable component of the SCE MPR model, as described in the draft decision. We agree, and make the appropriate correction.

Modeling (Peaking Issues). Although SCE is in support of the overall MPR methodology, SCE is concerned that the draft decision's use of a "relatively low capacity factor" for a "peaker plant proxy" is in fact too low. SCE states that peaker plants do not typically operate during non-peak hours in contrast to renewables. Accordingly, SCE recommends the use of a peaking proxy plant capacity factor in the range of 25-30%. In support of this position, SCE states that it "has not received, and does not foresee receiving, bids from renewable projects offering to meet a lower capacity factor like 9-10%."

TURN and GPI suggest that the Commission consider the use of a time-adjusted MPR. TURN provides the follow overview of such an approach:

"Under this approach, each utility would include time of delivery payment schedules for approval in its renewable procurement plan. Any bid would be compared, using the delivery profile submitted by the developer, to the time-adjusted MPR pricing schedules adopted as part of the procurement plan. If the total bid price (on a net present value basis) is higher than the comparable MPR pricing for the expected hours of delivery, the utility would be allowed to condition approval of a final contract on the award of Supplemental Energy Payments."

"[This would] ... allow utilities to benchmark non-standard products against the MPR without having to shoehorn the bid into either the "peaker" or "baseload" category. In particular, some peak-weighted renewable products are unlikely to have the precise characteristics of typical peaking generation and may offer deliveries during both peak and off-peak hours. It is also possible that shaped products (flat blocks of 24 x 7 power, with an additional block during peak hours) bid into a utility solicitation will be difficult to compare to the MPRs proposed in the [draft decision]." (TURN Comments, pp.1-2, emphasis added.)

TURN does note, however, that a change in MPR methodology at this late stage may not be feasible, in which case it could be considered for use in 2005. We agree that such an approach has merit, but does not appear feasible for use in 2004.

ORA, reprising its testimony in R.01-10-024, proposes revisions to the MPR methodology to account for the different Effective Load Carrying Capability (ELCC) of specific renewable technologies like wind and solar. As proposed by ORA, this approach seems to produce counterintuitive results, such as wind and solar plants having a higher capacity value than a CCGT when calculating a baseload MPR. SCE characterizes the results as absurd. As we stated in D.03-06-071, we believe that the ELCC approach may have merit, but it is better applied in the context of Least Cost/Best Fit bid ranking methods, where the utility will assess a renewable generator's ability to provide the value, in energy and capacity, expressed by the MPR proxy.

Modeling (Input Selection). On the issue of input selection criteria or guidelines, CalWEA recommends using "broadly representative" proxy plant costs, which is actually a "middle-of-the-road position," not an "other end of the spectrum" position, as characterized in the draft decision (CalWEA Comments, p. 2). GPI recommends using input assumptions that are "broadly representative, rather than lowest-price" and recommends using a "fully-loaded" capital cost (p. 2). SCE's previously stated position is to select inputs that would produce the lowest MPR, like that which would result from a competitive power solicitation under current market conditions. We take these comments in the form of guidance, and note that the draft decision states that, "a consistent set of input assumptions [are to be used calculating the MPR] that would account for certain cost tradeoffs. For example, plants with higher capital costs may be expected to have lower heat rates, and plants with higher variable O&M expenditures may have less heat rate degradation over time."

The draft decision does not specify whether the baseload and peaker proxy plants will be air-cooled or water-cooled. In its comments on the draft decision, Vulcan suggests that the Commission specify air-cooled proxy plants rather than water-cooled proxy plants, in order to avoid the difficult task of correctly estimating the cost of water to use in cooling water-cooled plants. No party took issue with Vulcan's recommendation, and it has both policy and practical advantages. Therefore, we will require the use of air-cooled proxy plants (baseload and peaker) for modeling purposes.

Process (Timing of MPR Disclosure). PG&E "strongly advises against the use of the term 'negotiations have been completed' as a trigger for disclosure" as set forth in the draft decision (p.6). CalWEA, San Diego, SCE, and TURN make similar recommendations. Instead, PG&E recommends that MPR disclosure occur after bidding has closed, but before a utility's final short list is developed. Specifically, PG&E recommends MPR disclosure via ALJ Ruling "before the utility tenders its tentative short list of prospective sellers to the PRG for review" (p. 8). San Diego makes a similar request, that MPR disclosure occur after initial bid ranking to allow PUC staff to participate in PRG review. SCE recommends not using the phrase "after negotiations are complete" (p. 7). CEERT's recommendation that MPR disclosure occur in the draft resolution does not appear well-founded, given that such a resolution would be drafted in response to a filed advice letter containing bid information. The Commission would not be able to accept such an advice letter for filing, as it would violate the RPS statute's "transmit and share" requirement. PG&E's detailed recommendations are helpful, and we adopt them as set forth herein.

In addition, TURN expressed concern that delayed disclosure of MPRs would prevent non-Commission PRG members from reviewing bids. We clarify here that it was not our intent to apply the "transmit and share" requirement to non-Commission PRG members.

Process (Degree of MPR Input Disclosure). CalWEA renewed its inquiry into the degree to which the Commission would disclose inputs used in the calculation of the MPR.

In reply comments, PG&E stated its agreement with CalWEA and SCE "that the MPR process should be modified to allow public review of the inputs, methodology, and calculation of the MPR by the Commission for this initial RPS solicitation" (p. 1). Specifically, PG&E suggests that this "post-facto review would not provide a basis for revisiting the MPR or any of the PPAs completed as a result of this RPS solicitation" and that "examination of the derivation of the MPR should provide a foundation for the efficient and accurate calculation of the MPR in future periods" (pp. 1-2). In its reply comments, San Diego is also supportive of this type of procedural review.

While this issue may not actually be integral to adoption of an MPR methodology, we acknowledge the need for transparency of the MPR calculation process, consistent with the limits imposed by the RPS statutes. Accordingly, the Joint Assigned Commissioner and ALJ Ruling disclosing the MPRs will have attached to it a staff report containing assumptions and inputs used to calculate the MPRs. Parties will be provided an opportunity to comment on the staff report, and the report and comments will provide the basis for a Commission decision that will guide future MPR calculations. This process provides a balance of allowing contracting parties to rely upon the MPR disclosed by the Ruling without fear of "second guessing," while also allowing for party input and full Commission oversight to ensure the ongoing fairness and consistency of the MPR calculation process and methodology.

Gas Forecasting (Use of NYMEX Data). TURN argues that all six years of NYMEX data should only be utilized if tied to "specific and substantial trading volumes" (p. 3). CEERT makes similar arguments. On the other hand, CalWEA, PG&E, SCE, and Vulcan support the use of the full six years. TURN further notes that the draft decision would actually "prevent the Commission from considering recorded volumes when deciding how to value pricing data that may result from few actual transactions." This is an important issue that covers ill-defined territory for both renewable energy development and natural gas forecasting. Accordingly, we direct staff to utilize portions of the NYMEX data as described above, but to continue to investigate the extent to which the full six years, or some subset of years, should be utilized. If the pending Commission determination regarding disclosure of the MPR methodology is compatible, we will make this staff analysis available for party comment.

Gas Forecasting (Years 7-20).

PG&E expressed concern that the Commission utilize a sufficient number of forecasts in determining the escalation factors applicable to the NYMEX price data. The be clear, Commission staff is directed to utilize multiple forecasts in calculating the escalation factor, and to evaluate each forecast in regards to its appropriateness for this task.

Gas Forecasting (Hedging Costs - Calculation and Application).

A number of parties took issue with the Proposed Decision's treatment of hedging costs in the NYMEX period. TURN offers a clarifying comment by separating the hedging concept into "insurance value" and "transaction costs". The former is what is gained by converting an expected future spot price for gas into a guaranteed delivery price at some future date. This value is captured by the proposed methodology of extending the NYMEX price data into the future utilizing the escalation factors inherent in a range of gas forecasts.

The latter component of hedging, the transaction costs element, reflects an important real component of a gas futures contract. Excluding it would result in the escalation of NYMEX prices that do not reflect the full expected cost of gas over the term of an RPS contract. PG&E's proposal to add one half the bid/ask spread, plus the collateral carrying cost, to the price of gas in the NYMEX years is broadly accepted by parties as a means of capturing these transaction costs. We adopt this approach, and modify the language above accordingly.

Gas Forecasting (Separate Peaking Gas Prices). PG&E recommends that the draft decision be corrected to reflect that there was, in fact, support for the use of separate peaking prices based on observed differences in summer month prices. Specifically, PG&E recommends that peaking MPR fuel cost be set at 95.8% of annual average prices on a nominal basis to reflect this average reduction in mid-summer gas prices (June through September).²⁶ We adopt PG&E's recommendation on this issue to the extent set forth herein.

Supplemental Energy Payments (SEPs). TURN raised a concern "that a utility might enter into a contract with a winning bidder that provides pricing above the MPR in some years, below it in others, and then require the seller to secure SEPs for every year in which pricing exceeds the MPR..." According to TURN, such an approach could allow the utility pay sub-MPR prices in some years while encumbering greater SEPs than are necessary on a net present value (NPV) basis. TURN's recommended solution is, in order for a bidder to become eligible to receive a SEP award, the total prices paid under any contract must exceed the MPR on an NPV basis as calculated over the entire contract term (p. 3). TURN's concern is a valid one, and while the awarding of SEPs is properly the province of the CEC, this analysis will be part of the examination this Commission will undertake in our review of utility contracts.

Findings of Fact

1. Pub. Util. Code §§ 399.14(a)(2)(A) and 399.15(c) require the Commission to adopt a process and methodology for establishing an MPR to be used in implementing the RPS program.

2. Commission D.03-06-071, as modified by D.03-12-065, began the implementation of determining a process and methodology for establishing an MPR.

3. Commission staff has issued a white paper and has held workshops and received comments on the subject of the MPR.

4. Different MPRs are needed for each contract term and power product.

5. Determining a methodology for establishing the MPR requires choosing a gas forecasting approach and a modeling approach.

6. NYMEX futures contracts are a source of forward market prices for natural gas.

7. Forecasts of forward market prices based on natural gas fundamentals are available from a number of sources.

8. A cash flow simulation model can be used to calculate baseload and peaking MPRs.

9. Calculation of MPRs requires a defined capital recovery term for both debt and equity.

10. A capital recovery term for both debt and equity of 20 years more closely matches reality than a shorter term.

11. Calculation of MPRs requires a defined capital structure.

12. The CEC model provides a capital structure that is a reasonable starting place for calculations.

13. The CEC model of capital structure does not exactly correspond to the facts in this proceeding.

14. Modeling inputs may be obtained from outside sources.

15. A combustion turbine is a reasonable proxy for a peaker plant for purposes of calculating an MPR.

16. It is reasonable to specify the use of air-cooled baseload and peaker proxy plants for MPR modeling purposes.

17. Pursuant to Pub. Util. Code § 399.14(a)(2)(A), the MPR must be disclosed only after the closing date of a competitive solicitation.

18. The timing of the disclosure of the MPR is important.

19. A Ruling allows for more precise timing of the disclosure of the MPR.

Conclusions of Law

1. There is an adequate record in R.01-10-024 and in this proceeding to adopt an MPR methodology.

2. Six statewide MPRs should be calculated, corresponding to the three contract terms and two power products.

3. In determining an MPR methodology, it is reasonable to use NYMEX gas futures prices and forecasts based on natural gas fundamentals.

4. In determining an MPR methodology, it is reasonable to use a cash flow simulation model.

5. A capital recovery term of 20 years for both debt and equity is reasonable to use for modeling purposes in calculating an MPR.

6. A 70/30 debt/equity ratio is reasonable to use for modeling purposes in calculating an MPR.

7. Commission staff should seek reliable outside sources for modeling inputs.

8. The same methodology and model should be used to calculate baseload and peaking MPRs.

9. Inputs for a peaking MPR model will be different from those for a baseload MPR model.

10. MPR disclosure should occur after bidding has closed, but before a utility's final short list is developed.

11. A Ruling is the preferable approach for the release of the MPR.

ORDER

IT IS ORDERED that:

1. A Market Price Referent methodology is adopted, as described above, consistent with the preceding Findings of Fact and Conclusions of Law.

2. The Assigned Commissioner and Assigned Administrative Law Judges will make such rulings as are necessary to effectuate this order.

3. This order is effective today.

Dated June 9, 2004, at San Francisco, California.

MICHAEL R. PEEVEY

President

GEOFFREY F. BROWN

SUSAN P. KENNEDY

Commissioners

I reserve the right to file a dissent.

/s/ LORETTA M. LYNCH

Commissioner

I reserve the right to file a dissent.

/s/ CARL W. WOOD

Commissioner

Appendix A to R0404026