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Parties Involved:
Federal Energy Regulatory Commission
Respondent
Mirant Americas Energy Marketing, L.P.
Intervenor
Southern California Water Company
Petitioner

Document Text:

United States Court of Appeals 

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued November 7, 2005 Decided December 30, 2005 

No. 04-1324 

SOUTHERN CALIFORNIA WATER COMPANY,

PETITIONER

V. 

FEDERAL ENERGY REGULATORY COMMISSION, 

RESPONDENT

MIRANT AMERICAS ENERGY MARKETING, L.P., 

INTERVENOR

On Petition for Review of Orders of the 

Federal Energy Regulatory Commission 

Randolph Lee Elliott argued the cause and filed the briefs 

for petitioner. 

Carol J. Banta, Attorney, Federal Energy Regulatory 

Commission, argued the cause for respondent. With her on the 

brief were Cynthia A. Marlette, General Counsel, and Dennis 

Lane, Solicitor. 

Before: HENDERSON and BROWN, Circuit Judges, and 

WILLIAMS, Senior Circuit Judge. 

Opinion for the Court filed by Senior Circuit Judge

WILLIAMS. 

USCA Case #04-1324 Document #940092 Filed: 12/30/2005 Page 1 of 12
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WILLIAMS, Senior Circuit Judge: Southern California 

Water Company, a public utility that distributes electricity to 

retail customers in San Bernardino County, California, 

challenges two orders of the Federal Energy Regulatory 

Commission. It contends that the Commission misapplied the 

concept of “incremental cost” as used in the Western System 

Power Pool (“WSPP”) Agreement; as a result, Southern 

California says, FERC incorrectly found that a sale of electricity 

by Southern California violated statutory filing requirements for 

the making of jurisdictional sales. See Federal Power Act, § 

201, 16 U.S.C. § 824. Because the Commission failed to explain 

its interpretation of incremental cost adequately, we reverse and 

remand. 

* * * 

At the beginning of March 2001, Southern California was 

committed to buying electricity for its retail customers in two 

wholesale contracts: (1) a baseload contract with Dynegy Power 

Marketing for 12 megawatts (“MW”) of around-the-clock 

energy at $35.50 per megawatt-hour (“MWh”), and (2) a 

contract with Illinova Energy Partners (“IEP”) to meet any 

hourly demand in excess of 12 MW at “SP15,” a name given the 

spot market price in the “South of Path 15” zone, a common 

delivery point. (Dynegy later assumed IEP’s obligations, but for 

ease in distinguishing between the baseload and the spot-price 

contracts we refer to this as the IEP contract.) As the Dynegy 

contract was scheduled to expire on April 30, 2001, Southern 

California entered into a contract with Mirant Americas Energy 

Marketing on March 16 to purchase 15 MW of around-the-clock 

energy at a price of $95/MWh. The contract was under the 

WSPP Agreement, which the parties identified as the “enabling 

agreement.” 

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For reasons not entirely clear, the Mirant baseload 

contract was to start April 1, 2001, and thus overlapped with the 

Dynegy baseload contract for the month of April. To address 

this overlap, Southern California entered into a separate contract 

with Mirant on March 30, 2001, again under the WSPP 

Agreement, agreeing this time to sell Mirant 15 MW of aroundthe-clock energy for the month of April at a price of SP15 minus 

$20/MWh. Although the overlap of baseload contracts 

obviously occasioned Southern California’s interest in making 

such a sale, the one-month contract was not formally tied to or 

contingent on the Mirant baseload contract. In the immediate 

run-up to the March 30 contract, the SP15 price fluctuated 

between a peak high of about $280 and an off-peak low of about 

$80. These were historically high prices; March 2001 fell in the 

midst of California’s well-known electricity crisis. 

At the time of the April 2001 sale, Southern California had 

no authority to sell energy at market-based prices. In July 2002, 

in a move unrelated to the April sale, it applied to the 

Commission for such authority. Mirant intervened, seeking a 

refund and contending that the April 2001 sale was itself at 

market-based rates. The Commission granted Southern 

California the requested authority prospectively, Southern 

California Water Co., 100 FERC ¶ 61,373 (2002), but 

simultaneously initiated an inquiry into the April 2001 sale. 

Southern California defended the sale on the ground that the 

rates were not “market-based” but cost-based, as they fell (it 

argued) within the WSPP Agreement’s cost-based limit–its 

provision that prices must not “exceed the Seller’s forecasted 

Incremental Cost” plus a so-called “adder.” It argued that the 

relevant incremental cost was SP15, the price that it would pay 

IEP for the last unit needed to meet the obligation to Mirant 

whenever its total sales commitments (i.e., the sum of (1) its 

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retail customers’ demand, which typically ran between 12 

and 17 MW, with occasional deviations in both directions, see 

Joint Appendix (“J.A.”) 310-23, and (2) the 15 MW needed for 

the April 2001 sale to Mirant) exceeded the 27 MW that it could 

count on from its baseload contracts with Dynegy and Mirant. 

The Commission rejected this defense, classified the sale as 

having been at market-based rates and therefore unauthorized, 

and ordered a refund of the difference between the revenue 

collected under the contract and $95/MWh (the price under 

Southern California’s baseload contract with Mirant), plus 

interest. See 106 FERC ¶ 61,305 (2004) (“Compliance Order”), 

order on reh’g, 108 FERC ¶ 61,168 (2004) (“Rehearing 

Order”). In denying rehearing the Commission explained its 

rejection of the argument that SP15 equaled “incremental cost” 

under the WSPP Agreement, saying that SP15 “would only be 

[Southern California’s] incremental cost once the sale to Mirant 

is consummated.” Rehearing Order, 108 FERC at P 14, p. 

62,022 (emphasis added). In addition, the Commission relied 

on the arguments that Southern California “simply resold” to 

Mirant the same energy that it bought, 106 FERC at P 17, p. 

62,198, and that the incremental cost could not have been SP15 

because SP15 exceeded its sale price of SP15 minus $20/MWh, 

108 FERC at P 14, p. 62,022. 

In a later order the Commission reduced the refund by the 

amount of an “adder,” which the WSPP Agreement allowed in 

excess of incremental costs for all sales under the Agreement 

that were not at market-based rates. The Commission explained 

that it now understood that the Agreement permitted sellers to 

charge the adder on top of the forecasted incremental cost, 

because the Agreement made “no distinction between owned 

resources and purchase contracts.” Southern California Water 

Company, 109 FERC ¶ 61,121 at P 12, p. 61,504 (2004). 

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Southern California challenges the Compliance 

Order and the Rehearing Order as being arbitrary and 

capricious, 5 U.S.C. § 706(2)(A), and as unsupported by 

substantial evidence, 16 U.S.C. § 825l(b). 

* * * 

The crux of the case is whether the Commission coherently 

explained its conclusion that the price of Southern California’s 

April sale to Mirant exceeded the cost-based ceiling established 

by the WSPP Agreement–Southern California’s “forecasted 

Incremental Cost.” The Agreement defines that term as “[t]he 

forecasted expense incurred by the Seller in providing an 

additional increment of energy or capacity during a given hour.” 

Western Systems Power Pool Agreement § 4.9, J.A. 219. 

The Commission’s prior orders have shed little interpretive 

light on the phrase. In initially approving the Agreement, the 

Commission said that “the seller's incremental cost for setting 

ceiling prices should be forecasted at the time of specific 

transactions under an agreement to reflect the actual cost with 

greater certainty” and that “incremental cost may be forecasted 

hourly, weekly, or monthly,” Western Systems Power Pool, 55 

FERC ¶ 61,099 (1991) (“Western Systems Power Pool I”), order 

on reh’g, 55 FERC ¶ 61,495 at 62,718 (1991) (“Western Systems 

Power Pool II”), aff’d sub nom., Environmental Action v. 

FERC, 996 F.2d 401 (D.C. Cir. 1993). In El Paso Electric Co., 

105 FERC ¶ 61,107 (2003), the Commission approved El Paso’s 

incremental cost methodology without explanation, but did make 

clear that a firm without authority for market-based sales could 

sell under WSPP’s incremental-cost ceiling, a point confirmed in 

NorthPoint Energy Solutions, Inc., 107 FERC ¶ 61,181 (2004). 

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At the outset the Commission’s understanding 

of incremental cost seems hard to square with the language of 

the WSPP Agreement. Recall that WSPP defines incremental 

cost as the “forecasted expense incurred by the Seller in 

providing an additional increment of energy or capacity during a 

given hour” (emphasis added). The Commission’s objection to 

Southern California’s reading of the Agreement was that SP15 

would only be its “incremental cost once the sale to Mirant is 

consummated.” Rehearing Order, 108 FERC at P 14, p. 62,022 

(emphasis added). In other words, the Commission faults 

Southern California for taking the projected sale into account, 

evidently reading the Agreement’s “in providing” to mean 

“without providing.” This linguistic twist might itself be 

grounds for reversal. 

Once we try to set the language in a purposive context the 

Commission’s approach appears still odder. Consider a seller 

with physical power-generating capacity, the type for which the 

WSPP Agreement was originally contemplated. See Western 

Systems Power Pool I, 55 FERC at 61,300. A seller with a 

portfolio of power-generating facilities can typically minimize 

the overall cost of providing any given total quantity by drawing 

on those facilities in increasing order of cost. Moreover, it 

seems plain that when contemplating an extra sale, the supplier 

must look at the facilities actually needed to make its total sales 

(the new one and those already contracted). 

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This is laid out in Figure 1, with the left-hand panel 

depicting costs as continuously increasing. See PAUL A.

SAMUELSON & WILLIAM D. NORDHAUS, ECONOMICS 116-18 

(16th ed. 1998). Better fitted to our case, and to the ordinary 

multi-plant electricity market, is the situation depicted in the 

right-hand panel, with cost levels coming in discrete segments. 

In that panel the seller owns three generating facilities, A, B, and 

C, with costs of $35.50/MWh, $95/MWh, and $180/MWh and 

capacities of producing 12 MW/h, 15 MW/h, and any 

foreseeably needed extra amount, respectively. If the seller at 

the outset has no commitments and then sells 10 MW of aroundthe-clock electricity to Buyer 1, costs are minimized if it 

produces at Facility A. The incremental cost of that sale—the 

cost of providing an additional MWh of electricity—would 

clearly be $35.50/MWh. As the seller increases its simultaneous 

sales, it moves to the right on the supply curve, progressively 

using more costly supplies. The right-hand panel plainly mirrors 

Southern California’s situation in making its sale to Mirant. 

Given its retail load of roughly 12-17 MW, the Mirant sale 

would compel Southern California to draw not only on its 

$95/MWh supply from Mirant but also on its SP15 supply from 

IEP. The only difference, an inconsequential one, is that Facility 

Figure 1: Illustration of Incremental Costs 

USCA Case #04-1324 Document #940092 Filed: 12/30/2005 Page 7 of 12
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C now represents purchases at SP15. Although the spot price 

obviously varies, $180/MWh represents Mirant’s prediction of 

the average SP15 price. 

But the language of the WSPP Agreement leaves some 

ambiguity. One possibility is to treat as decisive the cost of the 

marginal unit (i.e., unit cost of raising production from (a) the 

contemplated total sales, minus one, to (b) the entire 

contemplated level of sales). In the context of trying to arrange 

for an efficient power market FERC has held that all sales at any 

given hour are to be at the cost of the marginal generator. See 

Pacific Gas and Elec. Co. et al, 77 FERC ¶ 61,204 at 61,806-07 

(1996). Under certain plausible assumptions such a pricing rule 

(for all units sold) tends toward efficient allocation of resources. 

See ALFRED E. KAHN, THE ECONOMICS OF REGULATION 65-70 

(2d ed. 1988). Cf. Ronald H. Coase, The Marginal Cost 

Controversy, 13 ECONOMICA, NEW SERIES 169 (1946) (arguing 

that where economies of scale have not been exhausted and 

therefore marginal cost is below average cost, the efficiency 

properties of marginal cost pricing are dubious). By analogy, 

the WSPP Agreement’s cost-based ceiling for the April 2001 

sale would be SP15. 

A linguistically available alternative would be to read 

incremental cost to mean the average additional cost of raising 

sales from roughly 12-17 MW to roughly 27-32 MW. Kahn, for 

example, observes that incremental cost sometimes refers to “the 

average additional cost of a finite and possibly a large change in 

production or sales.” KAHN, at 66. Under this view the ceiling 

dictated by the WSPP Agreement would be a weighted average 

of $95/MWh and SP15. 

Other linguistically possible readings may exist, but the 

Commission’s is not among them. In the Rehearing Order it 

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rejected any consideration of the sale itself, and it adheres to 

that position on appeal, saying that the WSPP Agreement refers 

to “the last increment of energy sold based on the Seller’s 

existing forecasted load at the time of sale, without including the 

contemplated sale.” Respondent’s Br. at 26 (emphasis added). 

At oral argument Commission counsel slightly modified the 

position, saying that the ceiling on a block of electricity would 

be the incremental cost of the first MW sold in the block. Oral 

Arg. Tape at 30:08. The distinction is immaterial here, as under 

both definitions the incremental cost would be $95/MWh. 

Obviously the Commission’s view would prevent any sale 

where obtaining adequate supply would force the seller to draw 

on resources more costly than those already relied on. The 

Commission unsurprisingly offers no suggestion of what 

purpose such a rule might serve. Under the view offered by 

counsel at oral argument, the seller could make the sale possible 

by breaking it into smaller bites, creating a new bite at any 

breakpoint in cost level. The effect of this (assuming the 

Commission permitted it) would be the same as using the 

average incremental cost for the entire block.1

 But the 

Commission’s rule was plainly to the contrary, as it read the 

Agreement as putting incremental cost at $95/MWh pure and 

simple, with no allowance whatsoever for the necessary 

purchases from IEP at SP15. 

 

1

 Even under the view stated in the Commission’s brief, a 

seller might conceivably be able to manipulate the rule so as to 

recover just under its average cost. By assuring that each sale bite 

included one unit at the next price up, it would set that as a base for 

its next sale. 

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There are doubtless other possible complications. Peakhour energy is plainly more costly than off-peak, a distinction 

reflected in SP15. One might question Southern California’s use 

of SP15 at off-peak hours when it could meet its entire demand 

with only its Dynegy and Mirant supplies. In Western Systems 

Power Pool II, however, the Commission seemed uninterested in 

such distinctions, saying that incremental cost “may be 

forecasted hourly, weekly, or monthly.” 55 FERC at 62,718. 

Moreover, peaking power can be provided in multiple ways. 

Further, it may be that special difficulties are posed by extending 

ordinary readings of the WSPP Agreement from sellers with 

their own generating capacity to sellers such as Southern 

California that rely on forward contracts. But the Commission 

has made no such claims. 

The Commission instead relied on two other arguments to 

support its conclusion that calculating incremental costs should 

exclude the sale in question. First, it found that Southern 

California “did not procure the energy it sold to Mirant from the 

spot market (or self-generate), but simply resold the energy it 

was contractually committed to purchase from Mirant,” and that 

therefore the incremental cost was $95/MWh. See Compliance 

Order, 106 FERC at P 17, p. 62,198; Respondent’s Br. 32-36. 

But the Commission does not explain how it reconciles this cost 

concept with the WSPP’s definition of “forecasted expense . . . 

in providing an additional increment of energy or capacity” 

(emphases added). By attempting to attribute a fungible good to 

particular sources, the Commission effectively guts the meaning 

of incremental cost. For example, suppose that a seller owns 

Facilities A & C in the right-hand panel of Figure 1, generating a 

total of 14 MW per hour (12 MW on A and 2 MW on C). If the 

seller now acquires Facility B, the acquisition does not mean that 

the forecasted incremental cost in a sale of 15 MW (for a total 

commitment of 29 MW) would be $95/MWh, simply because 

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the sale amount equals Facility B’s capacity. The forecasted 

cost of making total projected sales would have to reflect costs 

at Facility C (and under the pure marginal cost principle the cost 

at C would apply across the board). 

Second, the Commission reasoned that the incremental cost 

could not have been SP15, because this would have meant that 

Southern California was simultaneously buying energy at SP15 

while selling it at SP15 minus $20/MWh. See Rehearing Order, 

108 FERC at P 14, p. 62,022; Respondent’s Br. at 30. The 

argument is evidently that if incremental cost were SP15, a sale 

at below SP15 was necessarily unreasonable from Southern 

California’s business perspective. This seems transparently 

wrong. Without the Mirant sale Southern California would not 

have come close to using the entire 27 MW capacity available to 

it in April under the Dynegy and Mirant baseload contracts. As 

a result it could improve its situation by making additional sales 

so long as the price was right. Selling 15 MW to Mirant at SP15 

minus $20/MWh would, to be sure, necessitate procurement of 

some units in the spot market at SP15, but by no means enough 

to offset the revenue from the sale. By the same token, the 

$20/MWh discount made the transaction attractive to Mirant–

which, because it had authority to sell at market rates, could 

count on being able to resell at SP15. Another alternative might 

have been for Southern California to sell a lesser amount–

calibrated to dispose of all surplus energy but also to obviate the 

need to make any purchases at SP15. We have no idea whether 

any such sale would have been feasible, and the Commission 

never suggests its availability, or indeed, any reason why the 

existence of such an option would be relevant to the incremental 

cost determination. 

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Finding no rational explanation for the 

Commission’s view that incremental cost under the WSPP 

Agreement for the April 2001 sale was $95/MWh, we must 

reverse. 

On remand, if the Commission should find that incremental 

cost was below SP15 minus $20/MWh (a conclusion we neither 

approve nor preclude), it must address the issue of remedy. 

Southern California calls our attention to a number of decisions 

of this court indicating that the Commission should apply 

equitable principles in calculating refunds in these 

circumstances, a duty the Commission completely neglected 

here. See Koch Gateway Pipeline Co. v. FERC, 136 F.3d 810 

(D.C. Cir. 1998); Laclede Gas Co. v. FERC, 997 F.2d 936 (D.C. 

Cir. 1993); Gulf Power Co. v. FERC, 983 F.2d 1095 (D.C. Cir. 

1993); Towns of Concord, Norwood & Wellesley v. FERC, 955 

F.2d 67 (D.C. Cir. 1992). The Commission responds that such 

cases are wholly inapplicable where, as its counsel argues, 

Southern California had made an “unauthorized and unreported 

sale of power in contravention of clear statutory and regulatory 

directives,” which counsel characterizes as “brazen.” 

Respondent’s Br. at 40-41. Obviously any conclusion based on 

such reasoning will require re-examination. 

The petition for review is granted and the case remanded for 

further action consistent with this opinion. 

 So ordered. 

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