Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-07-01217/USCOURTS-caDC-07-01217-0/pdf.json

Parties Involved:
Federal Energy Regulatory Commission
Respondent
Imperial Irrigation District
Petitioner

Document Text:

United States Court of Appeals 

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued February 25, 2010 Decided July 23, 2010 

No. 07-1208 

SACRAMENTO MUNICIPAL UTILITY DISTRICT, 

PETITIONER

v. 

FEDERAL ENERGY REGULATORY COMMISSION, 

RESPONDENT

CALIFORNIA INDEPENDENT SYSTEM OPERATOR CORPORATION,

ET AL., 

INTERVENORS

Consolidated with 07-1216, 07-1217, 07-1513, 08-1298,

08-1311 

On Petitions for Review of Orders 

of the Federal Energy Regulatory Commission 

Carolyn F. Corwin and Harvey L. Reiter argued the 

causes for petitioners San Diego Gas & Electric Company and 

Sacramento Municipal Utility District on CRR Issues. With 

them on the briefs were James R. Dean, Jr., Don Garber, and 

Lucy Holmes Plovnick. William L. Massey and Glen L. 

Ortman entered appearances. 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 1 of 44
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Lisa G. Dowden, Harvey L. Reiter, and Deborah A. 

Swanstrom argued the causes for petitioners City and County 

of San Francisco, California, Imperial Irrigation District, and 

Sacramento Municipal Utility District on Tariff Charge 

Issues. When them on the briefs were Meg Meiser, Theresa 

Mueller, M. Denyse Zosa, and Lodie D. White. 

Sean M. Neal, Michael Postar, and Bhaveeta K. Mody

were on the brief for intervenors Modesto Irrigation District 

and Transmission Agency of Northern California in support 

of petitioners. Wallace L. Duncan and Derek A. Dyson

entered appearances. 

Beth G. Pacella, Senior Attorney, and Samuel Soopper, 

Attorney, Federal Energy Regulatory Commission, argued the 

causes for respondent. With them on the brief was Robert H. 

Solomon, Solicitor. 

Kenneth G. Jaffe argued the cause for intervenors in 

support of respondent. With him on the brief were Michael E. 

Ward, Nancy J. Saracino, Daniel J. Shonkwiler, Roger E. 

Collanton, Jennifer L. Key, E. Kathleen Moore, Christopher 

C. O'Hara, Arthur Lawrence Haubenstock, Charles Ragan 

Middlekauff, Jeffery D. Watkiss, and Stuart Caplan. Bradley 

R. Miliauskas entered an appearance. 

Before: BROWN, GRIFFITH and KAVANAUGH, Circuit 

Judges. 

PER CURIAM: Following the California energy crisis of 

2000–01, the California Independent System Operator 

(California ISO or the ISO) began the process of redesigning 

California’s electricity market. The Federal Energy 

Regulatory Commission (FERC or the Commission) issued a 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 2 of 44
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series of orders providing guidance on California ISO’s 

proposals. Ultimately, in four orders issued between 2006 and 

2008, the Commission approved the ISO’s new market 

design, rejecting the numerous objections lodged by at least 

sixty-seven intervenors. Four parties—the Sacramento 

Municipal Utility District (Sacramento), the Imperial 

Irrigation District (Imperial), the City and County of San 

Francisco (San Francisco), and the San Diego Gas & Electric 

Company (San Diego)—now petition for review of these 

orders. Sacramento and Imperial challenge California ISO’s 

“locational marginal pricing” rate design, arguing in particular 

that it is unreasonable and unlawful to charge customers for 

the marginal cost of transmission losses. San Francisco 

challenges the “local resource adequacy requirement” 

imposed by California ISO, claiming it deprives San 

Francisco of the value of a preexisting contract. Finally, San 

Diego and Sacramento challenge aspects of the financial 

mechanism California ISO devised to allow customers to 

hedge against congestion costs. We find no merit to these 

arguments and therefore deny the petitions for review. 

I. Background 

A. The Parties 

 “In 1996, the Commission ordered the national 

deregulation of electricity transmission services. Order No. 

888 required utilities to ‘unbundle’ their electricity generation 

and transmission services and to file new ‘open access’ 

tariffs—modeled on a pro forma tariff included in the 

rulemaking—guaranteeing non-discriminatory access to their 

transmission facilities by competing generators.” Sacramento 

Mun. Util. Dist. v. FERC, 428 F.3d 294, 295–96 (D.C. Cir. 

2005) (“Sacramento I”) (citing Promoting Wholesale 

Competition Through Open Access Non-Discriminatory 

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Transmission Services by Public Utilities; Recovery of 

Stranded Costs by Public Utilities and Transmitting Utilities, 

Order No. 888, 61 Fed. Reg. 21,540 (Apr. 24, 1996) (“Order 

888”)).1 Order 888 also encouraged public utilities “to 

participate in Independent System Operators (‘ISOs’).” Cal. 

Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 397 (D.C. 

Cir. 2004). “An ISO conducts the transmission services and 

ancillary services for all users of such a system, replacing the 

conduct of such services by the system owners . . . . FERC 

deems it crucial that an ISO be independent of the market 

participants so that decisions of policy, operation, and dispute 

resolution be free of the discriminatory impetus inherent in 

the old system.” Id. (citing Order 888 at 31,731). 

Thus, in 1996, the California legislature chartered 

California ISO, “a non-profit organization that took over 

operation (but not ownership) of many transmission facilities” 

in the state. Sacramento Mun. Utility Dist. v. FERC, 474 F.3d 

797, 798 (D.C. Cir. 2007). California ISO maintains a tariff, 

subject to approval by the Commission, setting forth the 

terms, conditions, and rates under which it provides electricity 

service to customers. Sacramento, Imperial, San Francisco, 

and San Diego are all “load-serving entities,” meaning they 

acquire electricity from California ISO for delivery to end-use 

consumers. The wholesale rates they pay are dictated by the 

ISO’s tariff. 

However, these four petitioners are not all alike. San 

Diego is a privately-owned utility that became a “participating 

transmission owner” in California ISO by turning over 

 

1

 We have previously traced in detail the historical developments that led 

the Commission to issue Order 888. See, e.g., Transmission Agency of N. 

Cal. v. FERC, 495 F.3d 663, 667 (D.C. Cir. 2007); Midwest ISO 

Transmission Owners v. FERC, 373 F.3d 1361, 1363–65 (D.C. Cir. 2004). 

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operational control of its transmission facilities to the ISO. 

See W. Area Power Admin. v. FERC, 525 F.3d 40, 44 (D.C. 

Cir. 2008). Thus, California ISO assumed the obligation to 

honor San Diego’s preexisting transmission contracts. By 

contrast, Sacramento, Imperial, and San Francisco are 

publicly-owned “non-jurisdictional” utilities that opted not to 

become participating transmission owners of California ISO. 

(They are called “non-jurisdictional” because, as 

governmental entities, they are not subject to FERC’s 

jurisdiction under §§ 205 and 206 of the Federal Power Act, 

see 16 U.S.C. § 824(f).) Accordingly, they own or co-own 

certain transmission facilities that are within California ISO’s 

“balancing authority area”2

 but are not part of the ISO’s grid. 

These entities retain “transmission ownership rights”—

contractual entitlements to use such facilities. 

B. The Market Redesign and Technology Upgrade 

Proposal 

“In 2000, wholesale prices for electricity in California 

increased dramatically and resulted in the now-infamous 

California energy crisis.” Pac. Gas & Elec. Co. v. FERC, 373 

F.3d 1315, 1317 (D.C. Cir. 2004). This prompted California 

ISO, at the behest of the Commission, to begin redesigning 

California’s electricity market to avoid any repetition of the 

2000–01 crisis. California ISO’s “market redesign and 

technology upgrade” proposal followed. Over the course of 

six years, the Commission issued more than thirty orders 

providing guidance to California ISO and its market 

participants on the various contours of the proposed changes. 

 

2

 A “balancing authority area”—also called a “control area”—refers to the 

collection of generation, transmission, and end-users within the metered 

boundaries of the California ISO system, with respect to which the ISO is 

responsible for maintaining a balance of supply and demand. 

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The Commission ultimately approved California ISO’s 

revised tariff in four orders issued between 2006 and 2008.3

Three features of this tariff are challenged here: its 

incorporation of marginal loss charges into locational 

marginal prices, its local resource adequacy requirement, and 

its congestion revenue rights mechanism. 

1. Locational Marginal Pricing 

California ISO proposed to use “locational marginal 

pricing” (LMP) to set wholesale electricity prices. With an 

LMP-based rate structure, prices are designed to reflect the 

least-cost of meeting an incremental megawatt-hour of 

demand at each location on the grid, and thus prices vary 

based on location and time. Each LMP consists of three 

components: (i) the cost of generation; (ii) the cost of 

congestion; and (iii) the cost of transmission losses. See First 

Market Redesign Order ¶ 50. The first component refers 

basically to the baseline cost of serving load4

 anywhere on the 

system in the absence of congestion and transmission losses. 

Id. With respect to the second component, we have explained: 

 

3 Cal. Indep. Sys. Operator Corp., Order Conditionally Accepting the 

California Independent System Operator’s Electric Tariff Filing to Reflect 

Market Redesign and Technology Upgrade, 116 F.E.R.C. ¶ 61,274 (Sept. 

21, 2006) (“First Market Redesign Order”); Cal. Indep. Sys. Operator 

Corp., Order Granting in Part and Denying in Part Requests for 

Clarification and Rehearing, 119 F.E.R.C. ¶ 61,076 (Apr. 20, 2007) 

(“Second Market Redesign Order”); Cal. Indep. Sys. Operator Corp., 

Order Conditionally Accepting Tariff Provisions, Subject to Modification, 

and Granting in Part and Denying in Part Rehearing, 120 F.E.R.C. 

¶ 61,023 (July 6, 2007) (“Third Market Redesign Order”); Cal. Indep. Sys. 

Operator Corp., Order Denying Requests for Rehearing and Clarification, 

124 F.E.R.C. ¶ 61,094 (July 28, 2008) (“Fourth Market Redesign Order”). 

4

 “Load” refers to end-use customers of the transmission system, the 

primary source of “demand” for electric energy. 

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LMP . . . incorporates the cost of congestion 

into the price of energy. Under the LMP 

system, [an ISO] takes into account the limits 

on available transmission capacity when 

determining the price of energy at each node in 

its transmission grid. This results in higher 

energy prices at nodes that require the use of 

congested transmission lines and lower prices 

in less congested areas. . . . LMP [therefore] . . 

. giv[es] market participants incentives to 

avoid congestion-causing transactions [and] is 

also more economically efficient: scarce 

transmission capacity is allocated to those who 

value it most instead of being physically 

rationed. 

Wis. Pub. Power, Inc. v. FERC, 493 F.3d 239, 250–51 (D.C. 

Cir. 2007). The third component, transmission losses, 

refer[s] to the amount of electric energy lost 

when electricity flows across a transmission 

system: it is a function of the square of the 

amount of the current flowing on the wire and 

of the resistance it encounters. In general, the 

current on a given transmission line remains a 

constant, and the loss associated with a single 

transmission of electricity is primarily a 

function of the distance the electricity is 

transmitted. [An ISO] must deliver to the 

electricity customer the entire amount 

contracted for, regardless of the inevitable loss, 

so a transmission customer [i.e., a load-serving 

entity] . . . generally compensates [the ISO] for 

lost energy either by providing more energy at 

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the injection point than the electricity customer 

receives at the withdrawal point, or by 

providing energy in-kind to the transmitting 

utility. 

Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 

1, 2 (D.C. Cir. 2002) (citation omitted). In other words, unless 

the load-serving entity self-supplies sufficient electricity to 

make up for the amount lost during transmission, it must 

compensate the ISO for the losses. 

 Transmission losses can be calculated on either an 

“average” or a “marginal” basis. If transmission losses are 

simply averaged system-wide and allocated to all load-serving 

entities pro rata, “cross-subsidies” result: “parties that 

schedule[] long-distance transmissions pa[y] too little, while 

those that schedule[] shorter transmissions pa[y] too much.” 

Wis. Pub. Power, 493 F.3d at 252. Marginal loss pricing, by 

contrast, “recovers transmission losses on a transaction-bytransaction basis by . . . treat[ing] every transmission as if it 

were the last (marginal) transmission on the system. This 

pricing scheme sends more efficient signals to market 

participants, but because transmission losses increase with the 

amount of current in the system, treating every transmission 

as the marginal transmission produces revenue in excess of 

actual losses.” Id.

 California ISO proposed to incorporate the marginal cost 

of transmission losses into LMPs, arguing this was “necessary 

to assure least-cost dispatch and establish nodal prices that 

accurately reflect the cost of supplying the load at each node.” 

First Market Redesign Order ¶ 66 (footnote omitted). The ISO 

acknowledged that revenue collection would exceed losses 

and therefore proposed to credit excess revenues back to loadserving entities on a pro rata basis by reducing the cost of 

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each megawatt hour purchased by a proportionate amount of 

the excess revenues. See id. ¶¶ 67–68. 

 Finally, California ISO proposed to create several zones, 

called “load aggregation points.” Within each zone, the ISO 

proposed to calculate an average zonal price based upon the 

weighted average of the nodal LMPs within the zone. 

Suppliers would continue to be paid the precise LMP at a 

given node, but consumers would pay the aggregated price of 

their zone. California ISO contended that using zonal pricing 

for load—for a transition period—would protect consumers in 

congested areas from the sudden increase in costs that 

otherwise would result from the switch to an LMP-based 

market.

The Commission approved California ISO’s adoption of 

LMP, finding it would “promote efficient use of the 

transmission grid, promote the use of the lowest-cost 

generation, provide for transparent price signals, and enable 

transmission grid operators to operate the grid more reliably.” 

First Market Redesign Order ¶ 63. The Commission accepted 

the ISO’s proposal to “reflect marginal losses in its 

calculation of LMP, because doing so sends more accurate 

price signals and assures least-cost dispatch.” Id. ¶ 90. 

Sacramento and Imperial challenge the Commission’s 

approval of California ISO’s proposal to include marginal loss 

charges in LMPs. They argue the Commission’s finding that 

marginal loss charges would “necessarily” lower costs was in 

conflict with the Commission’s previous orders and lacked 

substantial evidence. Sacramento also challenges the 

Commission’s finding that marginal loss charges would result 

in transmission service equivalent or superior to that offered 

under FERC’s pro forma tariff. Imperial challenges the 

Commission’s finding that marginal loss charges would lead 

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to “just and reasonable” rates and further argues the 

Commission exceeded its statutory jurisdiction by authorizing 

the ISO to assess marginal loss charges to transactions in 

which Imperial uses its transmission ownership rights. 

2. Resource Adequacy Requirements 

 

 “Resource adequacy is the availability of an adequate 

supply of generation or demand responsive resources to 

support safe and reliable operation of the transmission grid.” 

First Market Redesign Order ¶ 3 n.2. The Commission 

explained that “ensur[ing] that all load serving entities 

procure adequate generation capacity to serve their load . . . is 

critical to maintaining reliability and ensuring that wholesale 

prices remain just and reasonable. Further, . . . resource 

adequacy requirements . . . will lessen the likelihood of price 

spikes occurring during periods of high demand.” Id. ¶ 4. As 

part of its market redesign proposal, California ISO proposed 

to impose on load-serving entities two types of resource 

adequacy requirements: “system” requirements and “local” 

requirements. System resource adequacy requirements are set 

by state authorities and aim to ensure there is sufficient 

generation in the entire California ISO balancing authority 

area to serve the ISO’s aggregate load. Local resource 

adequacy requirements are imposed on entities that serve load 

in constrained areas—known as “local capacity areas” or 

“load pockets”—where the transmission capability is 

insufficient to reliably serve 100% of the load without relying 

on generation capacity that is physically located within that 

area. California ISO proposed to perform an annual technical 

study to calculate the minimum amount of generation capacity 

that must be available within each local capacity area. Then, 

responsibility for acquiring the necessary local resources 

would be allocated to the applicable load-serving entities in 

accordance with each entity’s share of load. 

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San Francisco contended it should be permitted to satisfy 

its local resource adequacy requirement with resources it 

could import from outside the load pocket it serves, pursuant 

to a preexisting firm transmission contract. California ISO 

refused, explaining that the local requirement could only be 

satisfied with resources physically situated within the load 

pocket. FERC sided with the ISO. San Francisco petitions for 

review, arguing FERC’s decision arbitrarily and capriciously 

abrogated its contractual rights. 

3. Congestion Revenue Rights 

As noted above, LMP incorporates the cost of congestion 

into the price of energy. To provide a measure of protection 

for customers desiring to hedge against the price uncertainty 

that can result from fluctuations in congestion, California ISO 

proposed a system of “congestion revenue rights” (CRRs). 

Congestion revenue rights are 

financial instruments that entitle their holders 

to be paid the congestion costs associated with 

transmitting a given quantity of electricity 

between two specified points. A party planning 

a transmission can thus hedge its exposure to 

congestion costs by acquiring a corresponding 

[congestion revenue right]. At the time of the 

transmission, the party will pay [the ISO] the 

applicable congestion costs, but will then 

receive the same amount back from [the ISO] 

in its capacity as the holder of the [congestion 

revenue right]. 

Wis. Pub. Power, Inc., 493 F.3d at 251 (citation omitted). 

California ISO proposed to offer two types of congestion 

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revenue rights: short-term (with terms of less than one year) 

and long-term (with ten-year terms). Both would be 

“obligation” rather than “option” rights. Obligation rights 

entitle the holder to a payment when congestion is in the 

direction of the congestion revenue right—that is, when the 

price at the withdrawal point is higher than the price at the 

generation point—but require the holder to make a payment 

to the ISO when congestion is in the opposite direction. 

Option rights, by contrast, entitle the holder to be paid but 

never require the holder to make a payment. 

California ISO proposed to allocate congestion revenue 

rights among load-serving entities according to an annual 

four-tier nomination process. For the allocation of short-term 

congestion revenue rights in Tiers 1 and 2 in the initial year, 

the ISO proposed to require that “nominations for CRR 

allocations . . . be source verified,” meaning that load-serving 

entities would be required to “demonstrate that, during a 

historical reference period, the [load-serving entity] had an 

entitlement to receive energy from the nominated sources to 

serve its demand.” First Market Redesign Order ¶ 712. The 

ISO explained that “basing the CRR allocation on a period 

that has already occurred avoids the potential for the 

allocation process to distort incentives to contract for energy.” 

Id. California ISO proposed to use April 2006 to March 2007 

as the historical reference period. San Diego objected, arguing 

that its transmission usage during this timeframe was 

unusually low and that the ISO’s proposal would unjustifiably 

cause San Diego to enter the congestion revenue right 

allocation process with a substantial deficit of rights on which 

to hedge its existing procurement decisions.

California ISO proposed to allow load-serving entities to 

convert the short-term rights they received in Tiers 1 and 2 

into long-term rights in the long term tier (Tier LT). Initially, 

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the ISO proposed to allow entities to convert 50% of their 

adjusted load metric (a calculation that measures an entity’s 

exposure to congestion costs) into long-term rights. But in 

response to San Diego’s objection, the Commission held that 

no more than 20% of an entity’s adjusted load metric may be 

nominated for long-term rights—although the percentage 

increases 10% annually in subsequent years until it reaches 

50%. 

In Tier 3 (actually the fourth tier), California ISO 

proposed to allow any load-serving entity to request any 

congestion revenue right. If demand exceeds the rights 

available, then every entity receives a pro rata share of the 

remaining rights. Finally, the ISO proposed to auction off any 

congestion revenue rights that remain after the four-tier 

process. Of course, at any stage in the process, load-serving 

entities are free to buy or sell congestion revenue rights 

through bilateral transactions with other market participants. 

Every year after the initial year, the same tiered nomination 

process is repeated, except allocations no longer are source 

verified. Instead, load-serving entities that previously have 

received short-term congestion revenue rights either can 

renew them or convert them to long-term rights. Third Market 

Redesign Order ¶ 164. 

San Diego and Sacramento petition for review of the 

Commission’s approval of California ISO’s congestion 

revenue right proposal. San Diego argues FERC did not go far 

enough in ordering a remedy suited to San Diego’s unique 

circumstances. Sacramento argues FERC acted arbitrarily and 

capriciously in determining that the ISO did not need to offer 

option rights in addition to obligation rights. 

We consolidated these petitions for review into the 

instant action. 

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II. Discussion 

“We review FERC’s orders under the arbitrary and 

capricious standard and uphold FERC’s factual findings if 

supported by substantial evidence.” Am. Gas Ass’n v. FERC, 

593 F.3d 14, 19 (D.C. Cir. 2010); see 5 U.S.C. § 706(2) 

(2006). “We affirm the Commission’s orders so long as FERC 

examine[d] the relevant data and articulate[d] a . . . rational 

connection between the facts found and the choice made. In 

matters of ratemaking, our review is highly deferential, as 

[i]ssues of rate design are fairly technical and, insofar as they 

are not technical, involve policy judgments that lie at the core 

of the regulatory mission.” Alcoa Inc. v. FERC, 564 F.3d 

1342, 1347 (D.C. Cir. 2009) (internal quotation marks and 

citations omitted). 

We will first address Sacramento and Imperial’s 

challenges to California ISO’s proposal to incorporate 

marginal loss charges into LMPs. Second, we will consider 

San Francisco’s argument regarding the effect of the ISO’s 

local resource adequacy requirement on its contractual rights. 

And finally, we will address Sacramento and San Diego’s 

objections to the ISO’s congestion revenue rights proposal. 

A. 

 The Commission approved California ISO’s proposal to 

incorporate marginal loss charges as part of the locational 

marginal prices the ISO will charge transmission customers. 

Sacramento and Imperial claim the Commission acted 

arbitrarily and capriciously in doing so. Some of the 

arguments in support of that claim are advanced jointly by 

both Sacramento and Imperial; other arguments are advanced 

only by one party or the other. 

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1. 

Both Sacramento and Imperial challenge FERC’s 

conclusion that marginal loss pricing would “necessarily 

reduce” the total cost of meeting electricity demand within the 

California ISO system. See Second Market Redesign Order 

¶ 41. They contend, first, that FERC’s conclusion constituted 

an unexplained departure from a guidance order issued by the 

Commission in 2004; and second, that FERC’s conclusion 

lacked substantial evidence to support it. Both arguments lack 

merit. 

First, FERC’s conclusion about the benefits of marginal 

loss pricing did not conflict with or depart from its 2004 

guidance order. 

In that 2004 order, FERC said it would “accept the 

CAISO’s proposal to use marginal losses in its calculation of 

LMPs because this approach helps to assure a least-cost 

dispatch.” Cal. Indep. Sys. Operator Corp., Order on Further 

Development of the California ISO’s Market Redesign and 

Establishing Hearing Procedures, 107 F.E.R.C. ¶ 61,274, at 

62,269 (2004). FERC also stated: “While we believe a 

marginal loss approach provides for the most efficient 

dispatch, we would be concerned if this application were to 

substantially raise implementation costs of the CAISO’s 

market redesign. We note that, if in the process of further 

developing the marginal loss proposal and tariff language the 

CAISO and market participants determine that use of average 

losses at inception would be more easily administered and 

less costly, then the CAISO may file to use average losses 

when it makes its tariff filing.” Id. at 62,270. In other words, 

the Commission in 2004 generally approved of the use of 

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marginal loss charges, but it left California ISO with 

flexibility to decide how quickly to implement those charges. 

 Sacramento and Imperial focus on the Commission's 

statement permitting flexibility in the implementation of 

marginal loss charges. They claim that this statement actually 

undermines FERC’s subsequent determination that marginal 

loss charges would “necessarily” lower the cost of meeting 

electricity demand. That is incorrect. As the Commission 

explicitly stated in its 2004 order, it was concerned about the 

possible “implementation” costs of moving to marginal loss 

pricing, which might justify the use of a different scheme “at 

inception.” Id. (emphasis added). The 2004 guidance order 

did not indicate any doubts as to whether the adoption of 

marginal loss charges would reduce costs in the long run. On 

the contrary, FERC’s 2004 statements were entirely consistent 

with its subsequent findings about the efficiency gains 

associated with marginal loss pricing. 

 Sacramento and Imperial also claim the 2004 guidance 

order required California ISO to consult with its stakeholders 

about the costs of using marginal loss charges. It did not. As 

FERC explained in response to Sacramento and Imperial’s 

protest, the 2004 order did not say anything about 

consultation; it only “required an explanation from the 

CAISO to the extent that it and its stakeholders determined 

that implementing marginal losses would be substantially 

more costly than implementing average losses.” Second 

Market Redesign Order ¶ 46. The Commission concluded that 

because California ISO never determined “that using marginal 

losses would raise the implementation cost of” its market 

redesign proposal, California ISO was not required to consult 

with its stakeholders about alternatives to marginal loss 

pricing, and thus it had “acted in accordance with the June 

2004 Order.” Id. We must defer to the Commission’s 

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reasonable interpretations of its own orders to the extent there 

is ambiguity, and this interpretation of the 2004 order was 

eminently reasonable. See Wis. Pub. Power Inc., 493 F.3d 

239. 

Second, FERC’s conclusion about the benefits of 

marginal loss pricing was supported by substantial 

evidence—that is, “such relevant evidence as a reasonable 

mind might accept as adequate to support the conclusion.” 

Consol. Oil & Gas, Inc. v. FERC, 806 F.2d 275, 279 (D.C. 

Cir. 1986) (internal quotation marks omitted). 

The record before the Commission contained evidence 

adequate to support the Commission’s finding of an efficiency 

gain from using marginal loss charges. In particular, that 

finding was supported by the testimony of Lorenzo Kristov, 

California ISO’s “Principal Market Architect,” and that of 

Farrokh Rahimi, California ISO’s “Principal Market 

Engineer.” See J.A. 340 (Prepared Direct Testimony of 

Lorenzo Kristov) (“By paying supply resources their nodal 

LMPs with marginal losses included the CAISO sends them 

price signals that correspond to operating levels consistent 

with the optimal Dispatch of resources to meet Demand.”); 

J.A. 886-87 (Prepared Direct Testimony of Farrokh Rahimi) 

(explaining calculation of marginal loss component of LMP). 

The Commission cited both experts’ testimony in support of 

its conclusion regarding the benefits of marginal loss charges. 

See Second Market Redesign Order ¶ 41 n.65. 

 Sacramento and Imperial argue that the Commission 

ignored contrary testimony from Ziad Alaywan, an energy 

industry consultant with experience working for California 

ISO. Alaywan questioned the reasonableness of the marginal 

loss charge proposal in two different ways: First, he predicted 

that California ISO’s decisions to charge zonal prices rather 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 17 of 44
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than nodal prices and to refund excess marginal loss revenue 

to customers would reduce the efficiency gains anticipated 

from the move to marginal loss pricing. Second, he stated that 

the volatility of marginal loss charges would create planning 

problems for long-term firm transmission customers. See J.A. 

1206–13 (Prepared Answering Testimony of Ziad Alaywan 

P.E.). In other words, Alaywan argued that using marginal 

losses would result in fewer benefits and more costs than 

expected. 

 FERC addressed Alaywan’s arguments. In response to 

the suggestion that zonal aggregation and refunding of excess 

revenues would reduce the benefits of using marginal loss 

charges, the Commission explained that (i) customers would 

face the same marginal-loss-charge differential across 

suppliers, and would thus have the same incentives to select 

the lowest-cost supplier, regardless of whether the customers 

paid a nodal or zonal price; and (ii) each customer would 

receive the same per-megawatt-hour rebate regardless of 

whether that customer chose a high-cost or low-cost supplier, 

so the rebates would not affect the customer’s incentives to 

choose the lowest-cost supplier. See Second Market Redesign 

Order ¶ 37 & nn.60–61. And in response to the contention 

that the volatility of marginal loss charges would create 

planning problems for long-term customers, the Commission 

found that “the overall benefits of” marginal loss charges 

“outweigh the perceived difficulties in hedging” those 

charges. Id. ¶ 42. Thus, the Commission reasonably 

responded to the issues raised by Alaywan’s testimony. 

 In any event, even if Alaywan’s testimony arguably could 

have supported a different conclusion on the costs and 

benefits of the marginal loss proposal, that would not mean 

FERC’s conclusion lacked substantial evidence. We must 

“defer[] to the Commission’s resolution of factual disputes 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 18 of 44
19 

between expert witnesses.” Elec. Consumers Res. Council v. 

FERC, 407 F.3d 1232, 1236 (D.C. Cir. 2005); see also Ariz. 

Corp. Comm’n v. FERC, 397 F.3d 952, 954-55 (D.C. Cir. 

2005) (FERC’s orders do not lack substantial evidence 

“simply because petitioners offered some contradictory 

evidence”) (internal quotation marks omitted). 

 Finally, Sacramento and Imperial maintain that the 

Commission’s conclusion about the benefits of using 

marginal loss charges lacked substantial evidence because it 

was based “solely on theoretical postulates.” Pet’rs’ Br. on 

Tariff Charge Issues at 24 (quoting Elec. Consumers Res. 

Council v. FERC, 747 F.2d 1511, 1518 (D.C. Cir. 1984)). In 

advancing that argument, Sacramento and Imperial 

misunderstand our precedent. As we have recognized, this 

Court’s rationale for vacating the FERC order at issue in our 

1984 decision in Electric Consumers was not that the 

Commission had relied on economic theory, but that it had 

“distorted the economic theory it claimed to apply.” 

Transmission Access Policy Study Group v. FERC, 225 F.3d 

667, 688 (D.C. Cir. 2000). Neither Electric Consumers nor 

any other case law prevents the Commission from making 

findings based on “generic factual predictions” derived from 

economic research and theory. Id. (quotation omitted). Under 

our precedent, therefore, it was perfectly legitimate for the 

Commission to base its findings about the benefits of 

marginal loss charges on basic economic theory, given that it 

explained and applied the relevant economic principles in a 

reasonable manner. 

2. 

Sacramento argues that California ISO’s proposal to use 

marginal loss charges was inconsistent with the requirement, 

embodied in FERC Orders 888 and 890, that tariff provisions 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 19 of 44
20 

be consistent with or superior to the terms of the 

Commission’s pro forma tariff. 

 FERC established the pro forma tariff in 1996, setting it 

out in Appendix D to Order 888. See Order 888 at 21,706–

24. The current version of the pro forma tariff, as revised 

most recently in 2007, appears in Appendix C to Order 890. 

See Preventing Undue Discrimination and Preference in 

Transmission Service, 72 Fed. Reg. 12,266, 12,503–31 (Feb. 

16, 2007) (“Order 890”). The pro forma tariff contains 

“minimum terms and conditions of non-discriminatory 

service.” Id. at 12,269 ¶ 14. Transmission providers may 

adopt tariff provisions that deviate from those of the pro 

forma tariff, but any deviations must be “consistent with or 

superior to” the terms of the pro forma tariff. Id. at 12,288–89 

¶¶ 143, 157; see also Order 888, 61 Fed. Reg. at 21,618–19; 

Sacramento I, 428 F.3d at 296. 

 Sacramento maintains that the adoption of marginal loss 

charges rendered California ISO’s proposed tariff inferior to 

the pro forma tariff in two distinct ways: (i) by making it 

harder for customers to hedge against price uncertainty, and 

(ii) by making it harder for customers to self-supply energy 

losses associated with their transactions. FERC addressed 

both of Sacramento’s arguments, and its conclusion that 

California ISO’s proposed tariff was consistent with the pro 

forma tariff was both reasonable and reasonably explained. 

First, Sacramento argues that because marginal loss 

charges are volatile and cannot be hedged, customers under 

the California ISO tariff are less able to avoid price 

uncertainty than are customers under the pro forma tariff. 

This is because the pro forma tariff enables customers to 

avoid price volatility by obtaining long-term physical firm 

transmission rights with fixed rates. Sacramento further points 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 20 of 44
21 

out that in 1999, FERC determined that a tariff that included 

variable congestion charges would be inferior to the pro 

forma tariff unless it offered customers an instrument for 

hedging against those congestion charges. See Cal. Indep. Sys. 

Operator Corp., Order Conditionally Accepting Proposed 

Tariff Changes, 87 F.E.R.C. ¶ 61,143, at 61,570 (1999); see 

also Sacramento I, 428 F.3d at 297. 

As the parties agree, at the present time no one has been 

able to develop a mechanism for customers to hedge against 

variable marginal loss charges. See Second Market Redesign 

Order ¶ 42 (“hedging mechanisms for marginal losses are in 

the experimental stage”); J.A. 1165 (Sacramento Protest) 

(“Marginal losses are inherently unhedgable.”). Therefore, 

Sacramento insists, FERC should have ruled that the inclusion 

of marginal loss charges without a marginal loss hedge made 

California ISO’s proposed tariff inferior to the pro forma

tariff. 

In the proceedings below, FERC sufficiently addressed 

Sacramento’s argument that the lack of a marginal loss 

hedging mechanism made California ISO’s proposed tariff 

inferior to the pro forma tariff. The Commission explained at 

length that a system of locational marginal pricing would 

benefit load-serving entities like Sacramento by providing 

more efficient dispatch and more accurate signals regarding 

the need for investment in particular generation or 

transmission facilities. See, e.g., Third Market Redesign Order 

¶ 246. However, because no one has been able to develop a 

marginal loss hedge, exposing customers to variable, 

unhedgeable marginal loss charges is currently a necessary 

cost of the shift to locational marginal pricing. FERC 

concluded that the benefits of locational marginal pricing 

outweighed that cost, so that a tariff with locational marginal 

pricing—even one lacking a marginal loss hedge—would be 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 21 of 44
22 

superior to a tariff without that pricing mechanism. See id.

(“the ‘total package’ of [locational marginal pricing] and 

[congestion revenue rights] is superior to a pure physical 

rights regime”); Fourth Market Redesign Order ¶ 100 (“the 

benefits of marginal losses outweigh the perceived difficulties 

in hedging them”). That determination involved a “policy 

judgment[] . . . at the core” of FERC’s “regulatory mission,” 

and we therefore afford it substantial deference. Alcoa, 564 

F.3d at 1347 (quotation omitted). 

Relatedly, Sacramento argues that when FERC denied its 

request for a “transition mechanism” to refund marginal loss 

charges to customers until a marginal loss hedge could be 

developed, the Commission made an unexplained departure 

from one of its own prior decisions. San Francisco et al. 

Reply Br. on Tariff Charge Issues at 10; see Midwest Indep. 

Transmission Sys. Operator, Inc., Order Conditionally 

Accepting Tariff Sheets To Start Energy Markets and 

Establishing Settlement Judge Procedures, 108 F.E.R.C. 

¶ 61,163 (2004) (“Midwest ISO”). Sacramento is wrong: 

FERC did not depart from Midwest ISO. In that case, the 

Commission conditionally approved the adoption of marginal 

loss charges but mandated a “transitional safeguard . . . 

suspending marginal loss charges above average or historical 

loss charges for a period of five years” in order to give 

customers “time to adjust” to marginal loss pricing. Id. at 

61,925-26 ¶ ¶ 66, 73–74. In this case, however, Sacramento 

never requested a “transitional” refund mechanism of the type 

FERC required in Midwest ISO. On the contrary, Sacramento 

cited Midwest ISO only in connection with its argument that 

marginal loss pricing would never be acceptable without a 

hedging mechanism—a mechanism that Sacramento itself 

suggested would be impossible to develop. Consequently, the 

Commission’s decision not to accept Sacramento’s suggestion 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 22 of 44
23 

to indefinitely postpone implementation of marginal loss 

pricing was not a “departure” from Midwest ISO. 

Second, Sacramento argues that because marginal loss 

charges cannot be “self-supplied” without overestimating the 

amount of the charges, customers under the California ISO 

tariff are less able to self-supply the energy losses associated 

with their transmission service than are customers under the 

pro forma tariff. 

As explained above, energy losses occur whenever a 

transmission provider delivers electricity to a transmission 

customer. The customer must account for those losses. Under 

the pro forma tariff, the customer has two basic options for 

doing so: It can either pay the transmission provider the value 

of the lost energy, or it can self-supply the losses by 

scheduling or providing additional energy to cover the energy 

that will be lost during transmission. See Promoting 

Wholesale Competition Through Open Access NonDiscriminatory Transmission Services by Public Utilities, 62 

Fed. Reg. 12,274, 12,310 (Mar. 4, 1997) (“Order 888-A”). A 

customer that chooses to self-supply losses can either generate 

the lost energy itself or purchase it from a third party. Id.

The pro forma tariff facilitates self-supply by requiring a 

transmission provider to tell its customers “what the energy 

and capacity loss factors would be for any transmission 

service it may provide so that potential customers will know 

the amount of losses to replace.” Order 888, 61 Fed. Reg. at 

21,583. Under the pro forma tariff, then, a customer taking 

service under a long-term contract can calculate the losses for 

which it will be responsible over the term of the contract and 

provide for those losses in advance, thereby avoiding risk and 

uncertainty. Under California ISO’s proposed tariff, however, 

marginal loss charges are variable and cannot be forecast with 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 23 of 44
24 

certainty. Therefore, Sacramento maintains, customers 

wanting to self-supply the energy losses associated with their 

future transmission service will not be able to do so as 

effectively under the California ISO tariff as they could under 

the pro forma tariff. See J.A. 1164 (Sacramento Protest). 

 In the proceedings below, FERC acknowledged that 

under the California ISO tariff, customers would not be able 

to predict marginal loss charges with certainty. But the 

Commission determined that this did not render California 

ISO’s tariff inferior to the pro forma tariff because customers 

would still be able to self-supply their transmission losses by 

“conservatively estimating” the amount of future loss charges. 

Second Market Redesign Order ¶ 47. FERC thus concluded 

that the “consistent with or superior to” standard of Orders 

888 and 890 is satisfied by a regime where self-supply 

requires conservative estimation. 

That conclusion is entitled to substantial deference, both 

as an interpretation of the parameters set by FERC’s own 

orders, see Wis. Pub. Power, 493 F.3d at 266, and as a 

judgment involving regulatory policy at the core of FERC’s 

mission, see Alcoa, 564 F.3d at 1347. The determination of 

how one tariff compares to another is a technical inquiry 

properly confided to FERC’s judgment. While it might have 

been preferable for the Commission to provide a fuller 

explanation of why the ability to “conservatively estimat[e]” 

losses is equivalent or superior to the ability to precisely 

predict losses, the Commission’s failure to discuss that issue 

at greater length is not fatal to its order. The Commission 

grappled with Sacramento’s objection and provided a rational 

justification for rejecting it, and we cannot say the 

Commission’s conclusion was unreasonable. 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 24 of 44
25 

3. 

Imperial contends that the system of locational marginal 

pricing proposed by California ISO was not just and 

reasonable as required by § 205 of the Federal Power Act. In 

support of that contention, Imperial makes two distinct 

arguments. First, Imperial asserts that California ISO’s tariff 

will not realize the theoretical benefits of including marginal 

loss charges in LMP because customers will pay zonal 

aggregate prices rather than nodal prices. Second, Imperial 

argues that the marginal loss charges in California ISO’s 

tariff, and the mechanism for refunding excess revenues from 

those charges back to customers, are not consistent with cost 

causation principles. We find that neither of these arguments 

has merit. 

First, as we have already explained, FERC reasonably 

responded to the argument that zonal aggregate pricing would 

prevent California ISO from realizing the benefits of 

locational marginal pricing. 

The Commission determined that having customers “pay 

zonal, and not nodal, prices” would neither “preclude leastcost dispatch” nor prevent “the economic efficiency benefits 

of marginal losses” from materializing. Second Market 

Redesign Order ¶ 37. The key point, FERC emphasized, was 

that “all suppliers will receive nodal prices that reflect the 

cost of marginal losses.” Id. (emphasis added). The 

Commission explained that this would ensure least-cost 

dispatch for the following reason: “The delivered cost of a 

source depends on its cost at the source’s location, plus costs 

for losses and congestion. Since all suppliers will receive 

nodal prices . . . the difference in marginal loss charges will 

be the same whether the load pays a nodal or a zonal price.” 

Id. In other words, FERC concluded that regardless of 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 25 of 44
26 

whether California ISO employed a zonal or nodal pricing 

structure, transmission customers would have the same 

incentive to select the lowest-cost supplier. 

The Commission had substantial evidence on which to 

base that conclusion, as its Principal Market Architect 

testified that “there is general agreement among experts and 

those who operate markets based on LMP that the most 

important element in achieving the operational benefits of 

LMP is to settle supply resources at nodal prices, and that it is 

much less important to settle Demand at nodal prices.” J.A. 

343 (Prepared Direct Testimony of Lorenzo Kristov). 

Imperial has not offered any meaningful response to the 

Commission’s reasoning on this point and has failed to show 

that the Commission’s conclusion was arbitrary or capricious. 

Second, FERC reasonably concluded that California 

ISO’s treatment of marginal loss charges was consistent with 

cost causation principles. 

California ISO proposed to credit excess revenues from 

marginal loss charges back to transmission customers on a 

pro rata basis by using those revenues to uniformly reduce 

the cost of each megawatt-hour purchased on the system. See

First Market Redesign Order ¶¶ 67–68. Imperial complains 

that this refund mechanism “lacks any rational nexus to 

specific ratepayers which actually paid more money than 

necessary to replace energy lost when transmission service 

was provided to them.” Pet’rs’ Br. on Tariff Charge Issues at 

37. 

FERC fully addressed that cost-causation argument 

below. The Commission acknowledged that because 

transmission losses increase exponentially with overall system 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 26 of 44
27 

usage, charging each customer for marginal losses rather than 

average losses will result in over-collection “roughly by a 

factor of two.” First Market Redesign Order ¶ 66. But the 

Commission explained that treating each transmission 

customer as the marginal customer is consistent with costcausation principles because “the cost incurred to serve any 

customer (while serving all other customers) is the marginal 

cost of delivering electricity to the customer.” Second Market 

Redesign Order ¶ 44. In other words, it is not “possible to 

determine a cost below marginal cost that any individual 

[customer] caused as a result of that customer’s use of 

electricity.” Id. Thus, it is “just and reasonable for a customer 

to pay a price for electricity that reflects the marginal cost of 

producing and delivering it to the customer.” Id. The 

Commission then reasoned logically that “since the price 

customers are paying (based on marginal losses) is the correct 

marginal cost for the energy they are purchasing, customers 

are not entitled to receive any particular amounts through 

disbursement of the over-collections.” First Market Redesign 

Order ¶ 94. 

The Commission’s explanation was reasonable. Although 

treating every customer as the marginal customer results in 

over-collection in the aggregate, that treatment is reasonable 

for each customer. No customer is less deserving than another 

of being treated as the marginal customer; therefore, no 

customer is entitled to demand a refund greater than its pro 

rata share of the excess revenues collected. 

Beside those two arguments, Imperial also claims that 

locational marginal pricing with marginal loss charges will 

not send accurate price signals to transmission customers 

because a customer “will not know the amount of those 

[marginal loss] charges at the time service is requested.” 

Pet’rs’ Br. on Tariff Charge Issues at 35. Because neither 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 27 of 44
28 

Imperial nor any other party raised that argument before the 

Commission, it has been forfeited. See 16 U.S.C. § 825l(b) 

(“No objection to [an] order of the Commission shall be 

considered by the court unless such objection shall have been 

urged before the Commission in the application for rehearing 

unless there is reasonable ground for failure so to do.”). In 

any event, we have previously accepted the precise rationale 

that FERC relied on in this case. See Wis. Pub. Power, 493 

F.3d at 252 (“Marginal loss pricing recovers transmission 

losses on a transaction-by-transaction basis by incorporating 

them into the LMP. . . . This pricing scheme sends more 

efficient signals to market participants . . . .”). 

4. 

 California ISO’s proposed tariff recognized that 

“[t]ransmission [o]wnership [r]ights represent transmission 

capacity on facilities that are located within the [California 

ISO balancing authority area] that are either wholly or 

partially owned by an entity that is not a [p]articipating 

[transmission owner].” Tariff § 17. For example, Imperial and 

San Diego (along with a third utility) jointly own the 

Southwest Power Link transmission line, which is located 

within the ISO’s balancing authority area. Because San Diego 

is a participating transmission owner of the ISO but Imperial 

is not, Imperial has transmission ownership rights entitling it 

to a share of the line’s transmission capacity. 

 California ISO proposed to treat transactions involving 

transmission ownership rights as follows: If a preexisting 

transmission ownership rights agreement specified a 

methodology for calculating transmission losses, the ISO 

would honor it. See First Market Redesign Order ¶ 1003. 

Otherwise, the transaction would be treated like any other on 

the ISO’s grid, i.e., the load-serving entity would be required 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 28 of 44
29 

either to self-supply sufficient electricity to cover 

transmission losses, or it would be charged the marginal cost 

of losses and would receive a pro rata refund of the revenue 

over-collection. See id. ¶ 976 & n.418. Imperial objected on 

the ground that holders of transmission ownership rights “are 

not using [California ISO’s] transmission system to deliver 

energy purchased from the [ISO]. . . . [Rather, they] are using 

their own transmission capacity.” Second Market Redesign 

Order ¶ 452. Therefore, Imperial argued, “loss provisions . . . 

should be matters negotiated between [California ISO] and a 

[transmission ownership rights] holder.” Id. The Commission 

rejected Imperial’s objection, explaining that California ISO 

could assess marginal loss charges to transactions involving 

transmission ownership rights when those transactions cause 

losses on the ISO’s grid. See id. ¶ 458. 

 Imperial petitions for review, arguing the Commission’s 

decision exceeded its statutory jurisdiction. “FERC’s 

interpretation of its own statutory jurisdiction is entitled to 

Chevron deference.” Detroit Edison Co. v. FERC, 334 F.3d 

48, 53 (D.C. Cir. 2003). Governmental entities such as 

Imperial “are exempt from the [Federal Power Act] and 

therefore exempt from FERC’s jurisdiction when they provide 

transmission services.” Transmission Agency of N. Cal., 495 

F.3d at 667 n.4; see 16 U.S.C. § 824(f). According to 

Imperial, by approving California ISO’s assessment of 

marginal loss charges to transactions involving Imperial’s use 

of transmission ownership rights, FERC unlawfully 

“dictat[ed] rates, terms or conditions of service . . . to a nonjurisdictional governmental entity’s use of its own 

transmission facilities” and effectively “compel[led] such 

entity to transfer . . . control over its transmission facilities to 

[California ISO].” Pet’rs’ Br. on Tariff Charge Issues at 41–

42. 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 29 of 44
30 

 This is a gross mischaracterization of what the 

Commission authorized. FERC made clear in its order that 

marginal loss charges could be applied only to “transactions 

that . . . involve injections and withdrawals from the 

[California ISO] grid” and could not be assessed “where the 

[transmission ownership rights] holder has no point of 

interface with the [ISO].” Second Market Redesign Order 

¶ 458 & n.432. And at oral argument, counsel for the 

Commission insisted the ISO could never charge for losses 

occurring on “[Imperial’s] own transmission ownership rights 

part of the system.” See Tr. of Oral Argument at 35:1–3; see 

also id. at 35:21–23 (“There will be no marginal loss charges 

under these orders for transmission over the transmission 

ownership right.”). Asked whether marginal loss charges 

could be assessed to any portion of a transaction that occurs 

“off the [California ISO] grid,” FERC’s counsel responded 

unambiguously in the negative. Id. at 36:15–18. Given these 

limitations, we are satisfied the Commission did not exceed 

its jurisdiction. Far from compelling Imperial to become a 

participating transmission owner of California ISO, FERC 

merely permitted the ISO to charge Imperial for the costs 

incurred by the ISO when Imperial conducts transactions that 

cause transmission losses on the ISO’s grid. The 

Commission’s proper exercise of its power to regulate 

California ISO’s rates was not transformed into a violation of 

its statutory jurisdiction by dint of its incidental effect on 

Imperial. See Transmission Agency of N. Cal., 495 F.3d at 

671–72 (holding FERC did not exceed its jurisdiction in 

passing judgment on a non-jurisdictional entity’s revenue 

requirement because such review was necessary in order for 

FERC to determine whether the ISO’s rates were “just and 

reasonable”). 

 An analogous issue was presented in Mich. Pub. Power 

Agency v. FERC, 405 F.3d 8 (D.C. Cir. 2005). There, 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 30 of 44
31 

following FERC’s assessment of annual charges on the 

Midwest Independent System Operator (Midwest ISO), the 

Commission approved Midwest ISO’s request to pass through 

a proportionate share of those charges to two nonjurisdictional governmental agencies. Id. at 11–12. The 

agencies petitioned for review, claiming FERC exceeded its 

jurisdiction in authorizing the “pass-through of annual 

charges for the portion of the transmission that they take 

pursuant to their ownership interests.” Id. at 12. We 

acknowledged that the Commission could “not . . . assess[] 

annual charges directly” on the agencies but held there was no 

“jurisdictional bar . . . to passing through a share of those 

charges to the [governmental] [a]gencies.” Id. at 13 (emphasis 

added). We reasoned that because “the [governmental] 

[a]gencies use [Midwest ISO’s] transmission system when 

they take transmission pursuant to their ownership interests,” 

and because “the Commission regulates that system and 

incurs costs for such regulation that it seeks to recoup through 

its annual charges,” the Commission was “empowered to . . . 

permit a public utility to pass through a proportionate share of 

its annual charge to [the governmental agencies].” Id. 

 Similarly, here, Imperial relies on California ISO’s 

transmission system even when it “take[s] transmission 

pursuant to [its] ownership interests.” Id.; see Second Market 

Redesign Order ¶ 458 (noting that “[e]ven though . . . the 

[transmission ownership rights] facilities are not a part of 

[California ISO], they are integrally connected to the [ISO’s] 

grid”); id. ¶ 484 (noting that “[transmission ownership rights] 

facilities . . . are interconnected with the [ISO’s] grid and, 

therefore, influence power flows on the grid”). For instance, 

the Commission and California ISO both assert that, because 

Imperial’s transmission ownership rights pertain to facilities 

located within the ISO’s balancing authority area, the ISO is 

charged with responsibility for supplying any electricity 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 31 of 44
32 

shortfall if Imperial does not self-supply sufficient electricity 

to cover all transmission losses. Even at oral argument, 

counsel for Imperial failed to dispute this proposition. See Tr. 

of Oral Argument at 28:19–25. Rather, counsel merely 

declared that Imperial always “self-suppl[ies] energy to make 

up for losses.” Id. at 28:25; see also id. at 30:1–3, 30:14–17. 

That, however, is a non-sequitur. Because Imperial causes 

transmission losses on California ISO’s transmission system 

when Imperial conducts transactions involving an injection or 

withdrawal from the ISO’s grid, see Second Market Redesign 

Order ¶ 458 & n.432, the ISO understandably desired to 

charge Imperial for the cost of those losses if Imperial 

happens not to self-supply sufficiently. The Commission 

reasonably concluded that it had jurisdiction, not to 

“authoriz[e] [California ISO] to charge Imperial for the use of 

its own facilities,” but to “allow[] the [ISO] to charge 

Imperial for services the [ISO] is providing under [its] [t]ariff, 

and for use of [California ISO]-controlled facilities.” Id.

¶ 485. 

 Imperial argues that even if the Commission did not 

exceed its statutory jurisdiction, it acted arbitrarily and 

capriciously in finding it “just and reasonable” to assess 

marginal loss charges to transactions involving nonjurisdictional entities’ use of transmission ownership rights. 

We disagree. As explained above, the Commission reasonably 

found that charging for marginal losses sends more accurate 

price signals, promotes efficient dispatch, and is consistent 

with cost causation principles. Imperial offered no persuasive 

reason why these same benefits would not also flow from 

assessing marginal loss charges to transactions involving 

transmission ownership rights. See Second Market Redesign 

Order ¶ 484. Nor did the Commission, as Imperial argues, 

“erroneously conflate[] the burden of proof” by obligating 

Imperial to prove that the ISO’s proposal was not “just and 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 32 of 44
33 

reasonable.” Pet’rs’ Br. on Tariff Charge Issues at 55. Rather, 

FERC properly placed the “initial burden of showing that the 

tariff proposal is just and reasonable” on California ISO. 

Second Market Redesign Order ¶ 14; see also id. ¶ 484. Then, 

after finding that the ISO had established that it was “just and 

reasonable” to assess marginal loss charges to transactions 

that cause losses on the ISO’s grid, see First Market Redesign 

Order ¶ 987, the Commission simply found that Imperial had 

failed to controvert that conclusion, see Second Market 

Redesign Order ¶ 458. Furthermore, we note that the 

Commission ordered California ISO to “honor specified loss 

percentages in [transmission ownership rights] agreements, 

and only assess marginal losses to [transactions involving 

transmission ownership rights] in the absence of such explicit 

loss percentages.” Id. ¶ 484. FERC sensibly concluded that 

this would provide “a reasonable accommodation” between, 

on the one hand, honoring the contractual rights of 

transmission ownership rights holders, and on the other hand, 

preventing undue discrimination among grid users and 

achieving the efficiency benefits of marginal loss pricing. See 

First Market Redesign Order ¶ 1003; Second Market 

Redesign Order ¶ 475. In sum, Imperial has failed to show 

that the Commission exceeded its jurisdiction or acted 

arbitrarily or capriciously in approving California ISO’s 

assessment of marginal loss charges in these limited 

circumstances. 

5. 

 In a final attack on FERC’s approval of marginal loss 

pricing, Imperial argues that the imposition of marginal loss 

charges—particularly on holders of transmission ownership 

rights—will deter utilities from making investments in 

transmission infrastructure. The Commission has recognized 

that its Congressionally-defined regulatory mission includes 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 33 of 44
34 

stimulating transmission investment. See, e.g., Order 890 ¶ 79 

(noting that the Energy Policy Act of 2005 “placed special 

emphasis on the development of transmission infrastructure”) 

(citing 16 U.S.C. § 824s). However, contrary to Imperial’s 

claim that FERC abdicated this responsibility, the 

Commission carefully analyzed whether California ISO’s 

proposed market reforms would incentivize smart, efficient 

infrastructure investment. For instance, the Commission 

explained that incorporating marginal loss charges into LMPs 

“will create financial incentives to dispatch the lowest cost 

energy,” and “[i]n the long-term, by making energy and 

congestion prices more transparent, . . . will help encourage 

transmission and generation investment at appropriate 

locations.” First Market Redesign Order ¶ 10. This finding 

was not arbitrary or capricious because, as explained at length 

above, the Commission reasonably found, based on 

substantial evidence, that charging for marginal losses would 

send more accurate price signals to market participants. It 

logically follows that marginal loss pricing “will signal more 

accurately the location where new transmission and/or 

generation needs to be built and where investments in demand 

response should be made.” Third Market Redesign Order 

¶ 254. Thus, the Commission had a sound basis for rejecting 

“Imperial’s claims that treatment of [transmission ownership 

rights] under [California ISO’s proposal] will create a 

disincentive for new transmission investment,” and 

concluding that “the assessment of marginal losses [to 

transactions involving transmission ownership rights] will 

provide a more accurate cost allocation mechanism than the 

application of average losses, and can help entities better 

predict cost exposure when planning transmission expansion.” 

Second Market Redesign Order ¶ 475. We see no merit to 

Imperial’s contention that the Commission failed to give 

adequate consideration to its arguments, or acted arbitrarily or 

capriciously in rejecting them. 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 34 of 44
35 

B. 

We next turn to San Francisco’s challenge to the resource 

adequacy requirement. San Francisco provides electricity to 

consumers situated within a load pocket, which means the 

capacity to transport power into the city is so limited that 

imported generation alone cannot reliably satisfy customer 

demand for electricity. First Market Redesign Order ¶ 1156 

n.507. To guarantee reliability, California ISO proposed a 

requirement that would call upon San Francisco to ensure that 

a certain amount of generation capacity is located within the 

load pocket. Id. ¶ 1156. San Francisco contends that its 

contracts to import electricity are as good as having locally 

generated power. FERC rejected this argument and denied 

San Francisco’s rehearing request. We deny the petition for 

review. FERC provided a reasoned explanation for its 

determination that San Francisco could not satisfy its local 

resource adequacy requirement with contractual rights to 

imported power. See E. Tex. Elec. Coop., Inc. v. FERC, 218 

F.3d 750, 753 (D.C. Cir. 2000). 

San Francisco’s argument misconceives the nature of the 

local adequacy requirement. The requirement exists to ensure 

a minimum amount of capacity is available within the load 

pocket. FERC argues this requirement is necessary because 

the physical limits of transmission facilities make it 

impossible to reliably meet the demand for energy in load 

pockets with outside resources alone. See Second Market 

Redesign Order ¶ 601. A contingency such as a weatherrelated transmission outage could disrupt the ability to import 

energy, leaving San Francisco’s residents powerless. The fact 

that San Francisco has contracted for imported power is 

irrelevant to this reality. As the intervenors supporting FERC 

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36 

put it, “contract rights will not keep the lights on.” Br. of 

Intervenors Supporting Resp’t at 43. 

San Francisco contends that the ISO’s stance abrogates 

San Francisco’s existing contract rights and reduces their 

value, violating the ISO’s duty to honor any contract executed 

by San Francisco prior to April 1, 1998. See Pac. Gas & Elec. 

Co., 81 FERC at 61,471–72. California ISO annually 

determines the amount of locally generated electricity 

required of San Francisco by calculating what it can and does 

import. See Second Market Redesign Order ¶ 601; First 

Market Redesign Order ¶ 1168. San Francisco suggests that 

the annual study insufficiently credits San Francisco for the 

full value of its existing transmission contracts. Pet’rs’ Br. on 

Tariff Charge Issues at 63, 64 & n.118. But San Francisco 

failed to challenge the methodology of the technical study 

before the Commission, so this argument is not properly 

before us. 16 U.S.C. § 825l(b); see Jackson County v. FERC, 

589 F.3d 1284, 1291 (D.C. Cir. 2009). 

The local resource adequacy requirement does not alter 

or diminish San Francisco’s preexisting contract rights. San 

Francisco continues to obtain the same resources for the 

agreed-upon price. Indeed, it may continue to satisfy customer 

demand however it sees fit using either locally generated or 

imported power, and could sell any excess power it generates. 

See Second Market Redesign Order ¶ 602. In fact, loadserving entities such as San Francisco need not meet their 

local resource adequacy requirement by generating electricity, 

but if they do not, they must shoulder the cost when 

California ISO makes up for any shortfall. Tariff Section 

43.7.2. San Francisco faces a new obligation that cannot be 

satisfied with the power it imports under its existing contracts. 

To be sure, San Francisco did not anticipate this requirement 

when it made its current agreements. But the fact that San 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 36 of 44
37 

Francisco may now value less the resources it obtains from its 

suppliers does not render FERC’s decision to uphold the 

requirement arbitrary or capricious. 

San Francisco argues that FERC’s decision to allow 

California ISO to permit imported power to satisfy the system 

resource adequacy requirements but not the local 

requirements was arbitrary and capricious. Again, San 

Francisco’s argument fails to understand the different reasons 

for the different requirements. California ISO implemented 

the system resource adequacy requirement to ensure adequate 

generation capacity within the ISO’s balancing authority area 

as a whole. Each load-serving entity must show it has access 

to enough generating capacity to ensure reliable operation of 

the grid and proper functioning of the markets for electricity. 

Load-serving entities may satisfy this requirement with power 

imported from outside the load pocket. San Francisco argues 

that if California ISO found imported power sufficiently 

reliable to satisfy the system resource adequacy requirement, 

it was irrational to exclude it from the local calculation. But 

the system and local adequacy requirements serve different 

objectives. The local requirement exists to prevent local 

shortages, and does so by requiring a set level of local 

production. The aim of the system requirement is to prevent 

ISO-wide shortages by ensuring that the load-serving entities 

collectively have the capacity, whether by local production or 

by contract, to obtain power sufficient to meet the ISO’s 

demand. First Market Redesign Order ¶ 1116. There is 

nothing arbitrary or capricious about permitting load-serving 

entities to satisfy these different requirements with different 

sources of power. 

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C. 

Finally, we consider two challenges to California ISO’s 

congestion revenue rights proposal. San Diego objects to the 

formula by which the ISO intends to allocate these rights, 

arguing that it will receive an inadequate share. Sacramento 

challenges the type of congestion revenue right FERC has 

approved, claiming the ISO must make available “option” 

rights as well as the proposed “obligation” rights. We reject 

both challenges. 

1. 

California ISO proposed allocating the initial congestion 

revenue rights based on transmission usage from April 2006 

to March 2007. FERC approved the use of this reference 

period because it was “reasonably representative of the period 

during which the rates will be in effect,” early enough that 

entities could not strategically enter into contracts to “cherrypick[]” the most valuable congestion revenue rights, and yet 

recent enough that the data was not stale. Third Market 

Redesign Order ¶ 155. 

San Diego claims it will receive too few congestion 

revenue rights because of its anomalously low transmission 

use from April 2006 to March 2007. San Diego speculates 

that it will be unable to make up for this shortfall by acquiring 

additional congestion revenue rights at later stages because 

demand will outstrip supply and holders of rights will sell 

them only at exorbitant prices. San Diego argues that it will 

be unable to acquire sufficient rights, and those that it 

purchases will be sold at inflated costs that it will have to pass 

on to its customers. 

To address this scenario, San Diego proposed that the 

measure of transmission usage should include not only 

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39 

transmission between April 2006 and March 2007 but also all 

contracts for future delivery that were in place during that 

period. Id. ¶ 145. In the alternative, San Diego recommended 

that congestion revenue rights should be renewable only for 

the duration of the underlying contracts that governed 

transmission usage during the reference period, in contrast to 

the 10-year renewal permitted under the ISO’s proposal. Id.

¶ 146. 

FERC considered San Diego’s proposals but declined to 

adopt either. Instead, FERC ordered California ISO to 

decrease the number of short-term congestion revenue rights 

that could be converted to long-term rights in the first years of 

the allocation process. Id. ¶ 157. California ISO originally 

proposed that entities could convert 50% of their load into 

long-term congestion revenue rights. In response, FERC 

required that the number start at 20% and rise to 50% over a 

three-year period. This change was intended to ensure that 

entities with higher initial allocations than San Diego would 

not be able to lock in long-term advantages. FERC reasoned 

that this approach would make more congestion revenue 

rights available in the free-choice tiers because rights that are 

not renewed revert to the free-choice tier and the ISO may 

allocate them to any party requesting them. At the same time, 

FERC’s approach continues to provide load-serving entities 

“a degree of certainty that they can either acquire long-term . . 

. or renew short-term” congestion revenue rights. Fourth 

Market Redesign Order ¶ 31; see also id. ¶ 32. 

San Diego requested rehearing, arguing that FERC’s 

modification to the allocation process did not fully address its 

concerns. In denying rehearing, FERC reiterated that the 

limitations it placed on the conversion of short-term rights to 

long-term rights would ensure the availability of sufficient 

congestion revenue rights. Id. ¶¶ 28, 32. Any further 

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limitations, FERC concluded, would not strike the best 

balance “between providing [entities] reasonable certainty 

that they can keep the [congestion revenue rights] associated 

with existing contracted resources and providing [them] with 

the flexibility to request new [congestion revenue rights] 

associated with future procurement decisions.” Id. ¶ 32. 

San Diego now argues that FERC’s failure to provide an 

effective remedy to an acknowledged problem is arbitrary and 

capricious and inconsistent with section 205 of the Federal 

Power Act. When reviewing FERC’s selection of a remedy, 

we give the Commission “great deference,” La. Pub. Serv. 

Comm’n v. FERC, 522 F.3d 378, 393 (D.C. Cir. 2008), 

because “[a]gency discretion is often at its zenith” when the 

agency is fashioning remedies, Towns of Concord, Norwood, 

& Wellesley v. FERC, 955 F.2d 67, 76 (D.C. Cir. 1992) 

(internal quotation marks omitted). We extend this deference 

to “a predictive judgment by FERC about the effects of a 

proposed remedy for undue discrepancies among operating 

companies.” La. Pub. Serv. Comm’n v. FERC, 551 F.3d 1042, 

1045 (D.C. Cir. 2008). As we have often noted, we “will set 

aside FERC’s remedial decision only if it constitutes an abuse 

of discretion.” La. Pub. Serv. Comm’n v. FERC, 174 F.3d 

218, 225 (D.C. Cir. 1999). We find no such abuse of 

discretion here. 

FERC explained that its decision was a product of 

balancing the competing policy goals of flexibility and 

certainty. In administering the allocation of congestion 

revenue rights, FERC must ensure that the process is flexible 

enough that load-serving entities can acquire new congestion 

revenue rights in later years to accommodate their evolving 

needs, while simultaneously providing load-serving entities 

with assurances that they have reliable and long-term 

congestion hedges for their current transmission usage. Fourth 

USCA Case #07-1217 Document #1256931 Filed: 07/23/2010 Page 40 of 44
41 

Market Redesign Order ¶¶ 28, 32. San Diego asks us to reject 

FERC’s policy determination in favor of San Diego’s own. 

This we will not do. FERC reflected on the competing 

interests at stake to explain why it struck the balance it did. 

“This court properly defers to policy determinations invoking 

the Commission’s expertise in evaluating complex market 

conditions.” Tenn. Gas Pipeline Co. v. FERC, 400 F.3d 23, 27 

(D.C. Cir. 2005). 

The Federal Power Act does not compel a different result. 

San Diego argues that the allocation process prevents it from 

acquiring the long-term transmission rights to which it is 

entitled under § 217(b)(4) of the Federal Power Act to support 

its long-term power supply arrangements. 16 U.S.C. 

§ 824q(b)(4). But as we have explained, this claim boils down 

to a dispute between the competing predictions of FERC and 

San Diego about how the market for revenue rights will 

operate in the future. San Diego speculates that it will be 

unable to obtain the rights it needs either in the free-choice 

tier or through bilateral transactions, while FERC predicts that 

its modification to the allocation process will allow San Diego 

to meet those needs. Fourth Market Redesign Order ¶ 34. “[I]t 

is within the scope of the agency’s expertise to make such a 

prediction about the market it regulates, and a reasonable 

prediction deserves our deference notwithstanding that there 

might also be another reasonable view.” Envtl. Action, Inc. v. 

FERC, 939 F.2d 1057, 1064 (D.C. Cir. 1991). FERC’s 

determination that the allocation process, taken as a whole, 

allows load-serving entities to obtain congestion revenue 

rights for both present and future needs was a reasonable one. 

Moreover, if, in the future, the allocation process results in an 

unjust outcome, San Diego may petition the Commission to 

order appropriate changes at that time under section 206 of 

the Federal Power Act, 16 U.S.C. § 824e (2006). See Fourth 

Market Redesign Order ¶ 34 n.36. 

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 FERC’s decision was also consistent with its precedent. 

San Diego cites several cases in which FERC excepted one 

market participant from rules applicable to other entities in 

order to ameliorate unjust results. See New Eng. Power Pool, 

101 F.E.R.C. ¶ 61,344, at 62,431 (2002); Midwest Indep. 

Transmission Sys. Operator, Inc., 108 F.E.R.C. ¶ 61,163, at 

61,928 (2004); Sw. Power Pool, 116 F.E.R.C. ¶ 61,162 

(2006), order on reh’g, 118 F.E.R.C. ¶ 61,035 (2007). San 

Diego suggests that FERC should likewise afford it special 

treatment in light of the allegedly unjust share of revenue 

rights it will receive. But San Diego has not requested an 

exception so much as a complete redesign of the rule. No 

cited precedent compels the imposition of either of the 

particular remedies San Diego demands in this case. Because 

FERC did not act arbitrarily or capriciously in rejecting San 

Diego’s proposed changes to the congestion revenue rights 

allocation process, we deny San Diego’s petition for review 

on this issue. 

2. 

Sacramento challenges FERC’s approval of California 

ISO’s decision to offer obligation congestion revenue rights, 

but not option rights. These rights concern congestion costs, 

which are the costs associated with transmitting energy 

between two points on the grid with varying congestion. The 

holder of an obligation right is entitled to a payment from the 

ISO when the congestion at the source point is lower than the 

congestion at the withdrawal point. But when the situation is 

reversed—when congestion at the source point is higher than 

at the withdrawal point—the holder of the obligation right 

must make a payment to the ISO. By contrast, option rights 

include only the entitlement to receive payments from the ISO 

and carry no obligation to make payments. 

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Sacramento argues that the ISO’s decision to offer only 

obligation rights violates Order No. 890, which requires that 

the ISO’s pricing approach be comparable to the former 

physical rights system. Sacramento’s argument boils down to 

a simple premise: With obligation rights, Sacramento faces 

the possibility of having to make congestion payments to the 

ISO. Under the physical rights system, it would never face 

this prospect. Therefore, Sacramento argues, the two systems 

are not comparable. FERC rejected Sacramento’s request for 

option rights, concluding that the premise of its argument was 

flawed. FERC concluded that obligation rights are in fact 

equivalent to physical rights. Fourth Market Redesign Order 

¶ 92. This conclusion was not arbitrary and capricious. 

 FERC relied on record evidence to explain its conclusion 

that obligation rights, when matched with a transmission 

schedule, are equivalent to physical rights, see J.A. 2274 

(Prepared Direct Testimony of Dr. Susan L. Pope); J.A. 448 

(Prepared Direct Testimony of Scott M. Harvey and Susan L. 

Pope); and “articulate[d] a satisfactory explanation for its 

action including a rational connection between the facts found 

and the choice made.” Williston Basin Interstate Pipeline Co. 

v. FERC, 519 F.3d 497, 499 (D.C. Cir. 2008) (internal 

quotation marks omitted). Usually, the congestion cost of 

energy at its source point will be lower than the cost at its 

withdrawal point. In these circumstances, an entity with a 

schedule to transmit energy between these two points and a 

matching obligation congestion revenue right engages in two 

transactions with the ISO. First, the load-serving entity pays 

to the ISO the congestion cost associated with transmitting the 

electricity from the source point to the withdrawal point. 

Second, the ISO pays the holder of the matching congestion 

revenue right the same congestion cost. The net effect of these 

two transactions is that the load-serving entity pays zero if it 

holds the corresponding congestion revenue right. The result 

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is the same in the unusual circumstance in which the 

congestion cost of energy at the source point is higher than at 

the withdrawal point. In these cases, the congestion cost 

associated with transmitting electricity is negative, and the 

load-serving entity receives a credit equal to the difference in 

congestion costs between the source point and the withdrawal 

point. The holder of the corresponding obligation right pays 

the ISO the same amount in congestion costs. Again, the net 

effect of these transactions is that if the load-serving entity 

also holds the corresponding congestion revenue right, it pays 

no congestion costs at all. Third Market Redesign Order 

¶ 223. Accordingly, we hold that FERC’s conclusion that “[a] 

party that submits a physical schedule that matches its 

obligation [congestion revenue right] should face little risk of 

negative payments,” Fourth Market Redesign Order ¶ 94; see 

also Third Market Redesign Order ¶ 226, was rationally based 

on record evidence. See Williston Basin, 519 F.3d at 499. 

III. Conclusion 

 For the foregoing reasons, the petitions for review are 

Denied. 

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