Sacramento Municipal Utility District v. Federal Energy Regulatory Commission

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.
 2

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
 3
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
 4
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).
 5
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.
 6
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.
 7

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
 8
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-by-
transaction 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 load-
serving entities on a pro rata basis by reducing the cost of
 9
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
 10
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.
 11

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
 12
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,
 13
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.
 14

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.
 15

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
 16
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
 17
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
 18
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
 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
 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
 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
 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
 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 Non-
Discriminatory 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
 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.
 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 least-
cost 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
 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
 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 cost-
causation 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
 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
 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 non-
jurisdictional 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.
 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,
 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 non-
jurisdictional 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
 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 non-
jurisdictional 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
 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
 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.
 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 weather-
related 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
 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, load-
serving 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
 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.
 38
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 “cherry-
pick[]” 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
 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
 40
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
 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.
 42
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.
 43
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
 44
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.