Market Price

The first of the statutory tasks before us is to adopt: "A process for determining market prices pursuant to subdivision (c) of Section 399.15" (§ 399.14(a)(2)(A).)⁸

Subdivision (c) of § 399.15 reads:

(c) The commission shall establish a methodology to determine the market price of electricity for terms corresponding to the length of contracts with renewable generators, in consideration of the following:

(1) The long-term market price of electricity for fixed price contracts, determined pursuant to the electrical corporation's general procurement activities as authorized by the commission.

(2) The long-term ownership, operating, and fixed-price fuel costs associated with fixed-price electricity from new generating facilities.

(3) The value of different products including baseload, peaking, and as-available output.

It is left up to the Commission exactly how it should take into consideration each of these factors. Subsection (1) requires the Commission to consider the price of specific contracts.

SCE advocates that the Commission should give significant weight to contracts in establishing a market price. (SCE Opening Brief, p. 25-26.) PG&E similarly argues that contracts provide a more accurate picture of market prices. (PG&E Opening Brief, p. 18) ⁹

While theoretically such contracts would provide a simple and relatively accurate measure of market price, in practice there needs to be a usable quantity of contracts meeting the statutory requirements, and it is not clear that such contracts presently exist. The record does not indicate that there are contracts sufficient in number or comparability to provide a basis for setting a market price. (See, e.g. UCS Opening Brief, p. 6, citing to testimony of TURN and CEERT; Solargenix Opening Brief, p. 6.) Accordingly, while the Commission will certainly consider any such contracts in determining a market price, we cannot rely significantly upon them at this time.

It is possible that in the future there will be more contracts that meet the statutory requirements, but given the recent history of electricity markets in California, the continued presence of DWR contracts, and the utilities' statements regarding their resource needs, we do not foresee that there will be a significant number of such contracts in the near future. As more contracts meeting the statutory description come into existence, the Commission will increase its reliance on such contracts.

In addition to the statutory requirements, SCE proposes that the Commission, in establishing the market price of electricity, should also consider broker quotes and bids that utilities received but did not accept. (SCE Opening Brief, pp. 26-28.)¹⁰ According to SCE, these quotes and bids function equivalently to executed contracts, and provide a valuable source of data.

TURN, CalWEA, and Ridgewood (among others) oppose the use of broker quotes or unaccepted bids in establishing the MPR. (TURN Reply Brief, pp. 10-14; CalWEA Reply Brief, pp. 16-17; Ridgewood Opening Brief, p. 15. ) According to TURN, CalWEA, and Ridgewood, the use of quotes or bids is inconsistent with the statutory language, which refers to contracts, meaning executed contracts. In addition, such bids or quotes may not provide accurate information. (Id.) TURN also notes that the use of quotes or bids creates an opportunity for manipulation of the market price referent. We agree that the use of bids and unaccepted quotes is not required by the statute, that they are not equivalent to executed contracts and that they should not be used as a significant basis for setting the market price referent.

As a fallback position, SCE argues that if the Commission decides not to use unaccepted bids and broker quotes to directly determine the market price of electricity, it should still consider such data as a check mechanism, to ensure that the market price that is established is "in the ballpark." (SCE Opening Brief, p. 29.) We will allow this use of bids and quotes as an additional source of information. Bid and quote data shall be provided to the staff for their review, but will be given relatively little weight.

Under subsection (2), the Commission is to determine a price based on the costs associated with new generating facilities. In theory, this price and the price established under subsection (1) should converge, but as SCE and TURN note, the electricity market in California is not in equilibrium, rendering such convergence less likely. (See, SCE Opening Brief, p. 28, citing TURN witness Marcus.) ¹¹

In examining the specified costs associated with a new generating facility, the Commission can look at a typical hypothetical plant as a proxy. Virtually all parties endorse this process, albeit with variations in what costs and assumptions should be included in the proxy, and what type of plant should be used for the proxy.

In determining an appropriate proxy plant, subsection (2) interacts with subsection (3), which requires us to consider the value of different products, including baseload, peaking, and as-available output. Most parties agree that a combined cycle plant is the appropriate proxy for the value of baseload. (See, e.g., SCE Opening Brief, p. 29; CalWEA Opening Brief, p. 8; ORA Opening Brief, p. 6; SDG&E Opening Brief, pp. 4-5.) We will use a combined cycle plant as the proxy for establishing the benchmark price of the baseload product.

There was also wide, if less universal, agreement regarding the most appropriate proxy for establishing a value for a peaking product. While some parties recommended using a combined cycle plant for this product (e.g., CalWEA), most parties acknowledged that a combustion turbine (CT) provided the most accurate proxy for the peaking product. (See, e.g., CEERT Opening Brief, p. 28; PG&E Opening Brief, p. 19; ORA Opening Brief, p. 10; SDG&E Opening Brief, p. 7.)¹² We will use a CT plant as the proxy for establishing the benchmark price of the peaking product.

Subsection (3) also requires that the Commission consider the value of as-available output. As-available (also referred to as intermittent) is a somewhat different creature than baseload and peaking. While baseload and peaking are relatively firm sources of power, differentiated by the type of load they serve and the times of the day or year they operate, an as-available resource is less firm, and may or may not operate at a particular time of the day or year. Some as-available resources may operate at times that correspond to daily or yearly peaks, while others may not. Accordingly, it is difficult, if not impossible, to use a proxy plant for determining the value of as-available output.

If sufficient and appropriate long-term fixed price contracts (as described in subsection (1)) for as-available products existed, then it would be possible to use those contracts to determine the market price for as-available products. We do not have evidence of contracts that are usable for this purpose. To the extent such contracts become available, we will consider them.

In the meantime, the applicable market price referent for an as-available resource will be either the baseload or peaking referent, depending on which product that resource bids. The actual payment made to an as-available resource should be based on its actual performance, as recommended by TURN (Ex. RPS-25, p. 20) and CalWEA (Ex. RPS-12, Chap. 2, p. 2). The implementation of the payment methodology for as-available resources is discussed further below, in the sections addressing least cost and best fit and standard contract terms and conditions.

In developing the appropriate costs associated with the relevant proxy plants, a number of parties recommend using the CEC's draft staff report "Comparative Cost of California Central Station Electricity Generation Technologies" as a starting point. (See, e.g., PG&E Reply Brief, p. 36; CEERT, Ex. RPS-1, p. II-6; Solargenix, Reply Brief, p. 12.) While the methodology and/or data used in the CEC report may need some adjustments or modifications, the CEC report provides a reasonable and objective starting point.

Coming up with the specific cost components of the proxy plants will require additional work, as a significant amount of detail remains to be developed. Collaborative Staff will examine the CEC report, consider the adjustments and modifications recommended by the parties in this proceeding, and will issue a report containing the Collaborative Staff's recommendations. Following issuance of that report, Collaborative Staff will conduct workshops to further refine the details of the approach to be used. In the interim, we will provide some guidance on issues that have already arisen.

We note that the CEC report does not include the cost of direct assignment transmission facilities.¹³ As the cost of these facilities is a direct cost to both a proxy plant and to participating renewable generators, it should be reflected in the MPR.

Another issue is the appropriate level of project-specificity and site-specificity in the cost analysis. The more project- and site-specific the analysis, the more accurately the proxy would reflect the project being analyzed. On the other hand, this would result in a potentially infinite number of market price referents, one for each project location and configuration. This would render the market price referent far from transparent, and would also be both cumbersome and contentious, with the assumptions for each project a potential source of litigation.

The statute does not require this level of detail. It calls for the proxy to be based upon new generating facilities. (§ 399.15(c)(2).) The use of the plural "facilities" indicates that more than one facility is to be used for the proxy plant. Accordingly, we are going to use representative statewide numbers for factors such as heat rate and line losses. We will only use location-specific costs when those costs have already been specifically quantified for a particular geographic region, such as the cost of emissions offsets.

One of the more actively litigated issues was whether the cost of gas hedging should be included in the proxy. The statute requires us to consider (among other things), long-term fixed-price fuel costs. (§ 399.15(c)(2).) In the absence of comparable long-term fixed gas supply contracts, hedging is an established and appropriate method of fixing future costs. (TURN Opening Brief, pp. 22-23; UCS Opening Brief, pp. 8-12; ORA Opening Brief, p. 7; SDG&E Opening Brief, p. 6).

SCE argues that if there is a market for actual fixed price fuel contracts with a term equivalent to the term of the RPS contracts, then the Commission should refer to those actual contracts, rather than using a hedge value. (SCE Opening Brief, p. 34.) There is, however, no evidence that such contracts currently exist. If some come into being at some point in the future, the Commission will consider them at that time. In the meantime, hedging provides a reasonable alternative, and is more consistent with the statute than ignoring the costs associated with obtaining fixed prices for fuel on a long-term basis.

PG&E initially argued that the gas hedging costs of a combined cycle plant are likely to be minimal, and therefore should not be included. (Ex. RPS-7, pp. 3-5.) Several parties, however, cited to a study by Lawrence Berkeley National Laboratory (Ex. RPS-28) that found potentially significant costs for gas hedging. (See, e.g., UCS Opening Brief, p. 10.) Roughly similar costs were presented by Platts Research and Consulting. (See, e.g., Vulcan Opening Brief, pp. 5-6.) Even if PG&E is correct, the mere fact that hedge costs are likely to be small does not mean that they should be excluded from consideration.

SCE and PG&E question the reliability and methodology used in the Lawrence Berkeley and Platts studies. (See, SCE Opening Brief, pp. 34-38.) For example, the Lawrence Berkeley study relied in large part on the now-defunct Enron Online, and was based on data dating from the year 2000. These are reasonable criticisms. Undoubtedly updated information and methodological refinements will be used in future studies, making them more accurate than the current Lawrence Berkeley and Platts studies. We do not adopt a specific hedge value or methodology here, but we direct Collaborative Staff to use the best available methodology and data to calculate a gas hedge value for the relevant proxy plant.

Several parties argue that other items should be added to the proxy plant cost. UCS argues that the proxy should include a component reflecting the cost of possible future environmental regulations. (UCS Opening Brief, pp. 12-13.) For example, UCS states that new environmental regulations, such as those regulating carbon dioxide, are likely to result in an increase in gas prices. (Id., p. 13.) The methodology we adopt today incorporates known and actual costs. The costs UCS would have us include are too speculative at present. (See, e.g., SCE Reply Brief, pp. 7-8; PG&E Reply Brief, p 37.) We will incorporate them only when they become more definite, both in likelihood and value. Other issues relating to the proxy inputs will be addressed in later phases of this proceeding, subsequent to the Collaborative Staff report and workshops described above.

CalWEA and SCE recommend that the Commission disaggregate its benchmarks into separate energy and capacity components. (CalWEA Opening Brief, pp. 6-7; Ex. RPS-5, pp. 13-14.) TURN, SDG&E and PG&E recommend that energy and capacity components of the market price referent be bundled into a single "all-in" benchmark. (TURN Reply Brief, p. 18.) Both sides argue that their position is both simpler and more accurate, but there are plusses and minuses for each approach. On balance, we find that the separate energy and capacity approach is preferable. We will adopt the CalWEA version, in which the Commission (rather than the utility) calculates the capacity benchmark. As CalWEA points out, the Commission has significant experience in this process. (CalWEA Opening Brief, pp. 8-9.) This issue is discussed further in the section addressing "Least Cost and Best Fit."

On another and more general legal issue, SCE argues that the Commission "cannot direct utilities to enter into contracts that exceed avoided cost as that term is defined under the Public Utilities' Regulatory Policy Act of 1978, 16 U.S.C. section 824a-3 et seq. ("PURPA"), as interpreted by the Federal Energy Regulatory Commission ("FERC")." (SCE Opening Brief, p. 20.)

TURN, CEERT, and CalWEA vociferously dispute SCE's position. TURN argues that SCE blurs the distinction between establishment of a uniform wholesale rate and a competitive bidding process that yields market rates, and that FERC has found PURPA preemption in the former scenario, but has not found PURPA preemption in the latter, nor has FERC found PURPA preemption in the case of a price limit for renewable resources, even when that limit is set above prevailing market prices. (TURN, Reply Brief p. 22.)

CEERT argues that SB 1078 does not create a wholesale rate for power purchases, but rather sets up a mechanism for determining eligibility for and quantity of PGC fund support. (CEERT Reply Brief, pp. 7-8.)

CalWEA raises similar arguments, namely that the RPS program's market price benchmarks do not establish wholesale rates, and that SCE misconstrues the avoided cost standard. (CalWEA Reply Brief, pp. 22-24.)

SCE does not argue that SB 1078 is in violation of federal law, but only that the Commission's implementation may, if the numbers come out too high, result in federal preemption. Even assuming arguendo that SCE is correct in its assertion that the market price referent cannot exceed avoided cost, there is no preemption problem here, as we are not directing SCE to enter into contracts that exceed avoided cost.

According to SCE, the Commission would be in conflict with federal law if it sets the market price referent above the cost of available alternatives and "establishes procurement targets that effectively mandate the utility to execute contracts at prices exceeding the alternatives but within the Commission's benchmark." (SCE Opening Brief, p. 21.) Under SCE's formulation, for preemption issues to arise, two things must happen: the market price referent must be set too high, and the Commission must require SCE to execute contracts at those too-high prices.

SCE overstates the strictness of FERC's preemption standard. The same FERC decision cited by SCE states that FERC gives "great latitude" to state commissions regarding the procedures selected to determine avoided costs. "The Commission [FERC] has not, and does not intend in the future, to second-guess state regulatory authorities' actual determinations of avoided costs (i.e., whether the per unit charges are no higher than incremental costs). Rather, the Commission believes its role is limited to ensuring the process used to calculate the per unit charge (i.e., implementation) accords with the statute and our regulations." (Southern California Edison Company, 70 FERC ¶61,125 at 61,677 (February 23, 1995).)

SCE is arguing that the Commission may run afoul of federal law if the actual numbers for the market price referent that come out of this process are too high. SCE's argument is inconsistent with FERC's holding on this point. The process for establishing the numbers must accord with federal law, but FERC will not second-guess actual numbers. The process used here for establishing the market price referent is consistent with PURPA, and is also largely consistent with SCE's proposed process.¹⁴

The second element that SCE states is required for preemption to occur is that the Commission must require SCE to execute contracts above avoided cost. (SCE Opening Brief, p. 21.) SCE argues that the Commission may set procurement targets that "effectively mandate the utility to execute contracts at prices exceeding the alternatives but within the Commission's benchmark." (Id.) SCE does not contend that the Commission is actually going to order it to sign a specific contract at a specific price, as occurred in the cited Southern California Edison case. (See also, Midwest Power Systems, Inc., 78 FERC ¶61,067 (January 29, 1997).) Instead, SCE claims that the requirement that SCE increase its procurement of renewable generation may mean that SCE will feel compelled to execute a contract at a too-high price. In essence, SCE is arguing that the Commission would indirectly require SCE to enter a contract at above its avoided cost.

However, the process adopted today pursuant to SB 1078 is far different from the processes at issue before FERC in Southern California Edison and Midwest Power Systems. Here, SCE gets to issue an RFO for bids from renewable generators, SCE gets to evaluate those bids, SCE gets to negotiate with the bidding generators, SCE gets to decide whether to execute a particular contract, and SCE gets the protection of the flexible compliance mechanism described below. SCE is not required to enter into any specific contract.

ORA recommends that the Commission use the effective load carrying capacity (ELCC) of a renewable technology as a significant part of the market price referent calculation methodology. (ORA Opening Brief, pp. 10-12.) According to ORA, the ELCC more accurately reflects the value of the peaking component of an intermittent resource, which the utilities may undervalue due to intermittent resources' non-dispatchability. Unfortunately, use of the ELCC is necessarily technology-based, which creates a range of issues and problems that are beyond the scope of what we can review in this phase of this proceeding, where our focus is necessarily upon the statutory requirement for a product-based market price referent. Nevertheless, we believe that the ELCC is a useful concept, and we may consider it when adjusting RPS program capacity payments in the future. Parties are encouraged to explore its use in future phases of this proceeding and related proceedings.