United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued February 26, 2008 Decided May 2, 2008
No. 04-1090
WESTERN AREA POWER ADMINISTRATION,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
SOUTHERN CALIFORNIA EDISON COMPANY, ET AL.,
INTERVENORS
Consolidated with
04-1095, 06-1362, 06-1370, 06-1371, 07-1081
On Petitions for Review of an Order of the
Federal Energy Regulatory Commission
Mark W. Pennak, Attorney, U.S. Department of Justice, and
Harvey L. Reiter argued the cause for petitioners Western Area
Power Administration, et al. With them on the briefs were Glen
L. Ortman, Lucy Holmes Plovnick, M. Denyse Zosa, Wallace
Lamar Duncan, Sean M. Neal, James D. Pembroke, Derek
Anthony Dyson, William S. Huang, and Meg Meiser. Anthony
A. Yang and Robert S. Greenspan, Attorneys, U.S. Department
2
of Justice, and Robert C. McDiarmid, Lisa S. Gast, and Peter J.
Scanlon entered appearances.
Rod S. Aoki argued the cause for petitioners Cogeneration
Association of California and Energy Producers and Users
Coalition. With him on the briefs were Michael Alcantar and
Donald Brookhyser.
Samuel Soopper, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on the
briefs were Cynthia A. Marlette, General Counsel, and Robert
H. Solomon, Solicitor. Patrick Y. Lee, Attorney, entered an
appearance.
Kerry C. Klein argued the cause for intervenors. With her
on the brief were Michael E. Ward, Mark D. Patrizio, and
Jennifer L. Key. Anthony J. Ivancovich and Bradley R.
Miliauskas entered appearances.
Before: RANDOLPH and GARLAND, Circuit Judges, and
EDWARDS, Senior Circuit Judge.
Opinion for the Court filed by Senior Circuit Judge
EDWARDS.
EDWARDS, Senior Circuit Judge: This case arises from the
reorganization of the electric transmission grid in the state of
California, the subsequent imposition of administrative fees by
the California Independent Systems Operator (“ISO”), and the
pass-through of those fees by Pacific Gas and Electric
(“PG&E”) to its customers. The decision of the Federal Energy
Regulatory Commission (“FERC” or “Commission”) to approve
the fees and pass-through has been challenged by several large
customers of PG&E – the Western Area Power Administration,
Northern California Power Agency, Sacramento Municipal
Utility District (“SMUD”), City of Santa Clara, and Modesto
Irrigation District (together “Existing Customers”) – as well as
the Cogeneration Association of California and the Energy
3
Producers and Users Coalition (together “CoGen”). The
petitioners argue that the Commission acted arbitrarily and
capriciously in approving fees that violated FERC cost-
causation principles and imposed new fees for existing services,
in violation of the Mobile-Sierra doctrine.
We uphold the Commission’s Order against both sets of
challenges. CoGen’s petition to this court was untimely.
Subject matter jurisdiction over challenges to a FERC order is
limited to petitions that are filed within 60 days of the
challenged order. 16 U.S.C. § 825l(b). Because CoGen did not
file its petition within that time frame, we cannot review its
merits. While we have jurisdiction over the petition of the
Existing Customers, we find that the Commission did not act
arbitrarily or capriciously in its approval of the California ISO’s
fees or the PG&E pass-through. We therefore uphold the
decision of the Commission.
I. BACKGROUND
In 1996, FERC inaugurated a “brave new regulatory world”
with Order No. 888. East Kentucky Power Coop., Inc. v. FERC,
489 F.3d 1299, 1301-02 (D.C. Cir. 2007). This Order was
“[p]romulgated in response to the anticompetitive effects of
vertical integration” where generation of electricity and
transmission of electricity was controlled by the same entity. Id.
at 1302. The Order attempted to increase competition in the
electricity business by “requir[ing] the functional unbundling of
wholesale generation and transmission services.” Id. (quotation
marks omitted). We have described Order No. 888 as follows:
If vertical integration (the predecessor to functional
unbundling) offered a prix fixe menu of utility services,
functional unbundling required the a la carte alternative:
Under the new system, previously integrated utilities were
now required to maintain a wholesale marketing function
separate from their transmission functions. . . .
4
In addition to the unbundling requirements that it imposed,
Order No. 888 encouraged, but did not demand, the
formation of Regional Transmission Organizations
(“RTOs”): multi-utility entities that could manage all
transmission services for a particular region. . . . FERC
suggested a further improvement to the novel system it
envisioned[:] The multi-utility RTO would cede
operational control of its collectively run transmission
facilities to an [ISO], which would have no financial
interest in generation services and therefore no incentive to
thwart FERC’s goals of efficiency, competition, and
improved reliability.
Id.
As the Commission was implementing Order No. 888, the
State of California chartered the California ISO as “an
independent entity that would take over transmission operations
from California utilities.” Sacramento Mun. Util. Dist. v. FERC,
428 F.3d 294, 296-97 (D.C. Cir. 2005). Upon taking over the
transmission grid, the California ISO would provide
transmission services on a nondiscriminatory basis. Prior to the
transition to the ISO, the three major privately-owned utilities –
PG&E, Southern California Edison, and San Diego Gas &
Electric – each had operated its own control area, performing the
coordination, administrative, and maintenance duties needed to
operate a reliable power system. Contracts between PG&E and
the Existing Customers, collectively referred to as the Control
Area Agreements, date to the time when PG&E held
responsibility for its control area. Upon the creation of the
California ISO, the privately-owned utilities became
participating transmission owners in the new system by turning
over control of their transmission facilities to the ISO. After
that transition, certain services contracted for by the Existing
Customers in the Control Area Agreements with PG&E were
provided by the California ISO.
5
In 1997, the California ISO filed its original proposed Grid
Management Charge which was designed to recover its start-up,
administrative, and operating costs. Letter from Charles
Robinson, General Counsel, California ISO, and Edward Berlin,
Swidler Berlin Shereff & Friedman, to David P. Boergers,
Secretary, FERC (Nov. 1, 2000) at 1, reprinted in Joint
Appendix (“JA”) 86. This charge was assessed on a monthly
basis against all ISO Scheduling Coordinators – the entities that
are responsible for scheduling electricity deliveries through the
ISO. Id. Under the new system, PG&E has been the Scheduling
Coordinator for the Existing Customers for all relevant time
periods.
In November 2000, the California ISO proposed a new Grid
Management Charge for the period from January 1, 2001 to
January 1, 2004. The revised Grid Management Charge
“unbundled” the earlier charge in order to “allocate costs fairly
among all ISO system users, and minimize cost subsidization
among” participants in California’s electrical market. Id. at 6,
JA 91. The ISO believed that unbundling the Grid Management
Charge would better reflect “the principle of cost causation”
which it defined as meaning that “the ISO’s costs, to the extent
possible, should be attributed to those entities that caused them
to be incurred.” Id. Tying fees closely to cost causation
facilitates market efficiency because more accurate “price
signals direct[] market behavior towards optimum results.” Id.
The Grid Management Charge was unbundled according to
three categories of services that the ISO provides: Control Area
Services, Inter-Zonal Scheduling, and Market Operations.
Control Area Services are the services that the ISO provides as
a Control Area operator to ensure “reliable, safe operation of the
transmission grid.” Id. at 8, JA 93. The ISO’s responsibilities
as a Control Area operator include
scheduling generation, imports, exports, and wheeling
transactions . . . ; insuring adherence to regional and
6
national reliability standards; monitoring and developing
transmission maintenance standards; performing
operational studies and system security analyses;
dispatching bulk power supplies; conducting system
planning to ensure overall reliability; . . . providing
emergency management; overseeing outage coordination;
and performing transmission planning.
Id. (footnote omitted). The costs incurred by the ISO for its
Control Area Services were allocated to Scheduling
Coordinators on a “gross load” basis. The ISO defined gross
load as “all Demand for Energy within the ISO Control Area.
Control Area Gross Load does not include auxiliary Load (i.e.
energy used in the power production process) or Load that is
electrically isolated from the ISO Control Area (i.e. Load that is
not synchronized with the ISO Control Area).” Id. The Inter-
Zonal Scheduling category of services is not at issue in this case.
Market Operations services “include the ISO’s cost of market
and settlement related services . . . includ[ing] the billing of, and
payments for, Energy, Ancillary Services capacity, and
transmission service into, within, and out of the ISO Control
Area.” Id. at 9, JA 94. The costs of the Market Operations
services were allocated to Scheduling Coordinators based on
“the proportion of a given [Scheduling Coordinator’s] total
purchase and sales of Ancillary Services, Supplemental Energy,
and Imbalance Energy . . . to the total purchases and sales of all
[Scheduling Coordinators].” Id. at 10, JA 95. The sum of the
charges for Control Area Services, Inter-Zonal Scheduling, and
Market Operations charges made up the Grid Management
Charge.
Shortly after the California ISO proposed the Grid
Management Charge, PG&E proposed a new tariff for Control
Area Agreement customers that would pass through the Grid
Management Charge to those customers. PG&E claimed that
the pass-through was justified, because Control Area Agreement
7
“customers are the direct beneficiaries of these ISO services. It
is from these [Control Area Agreement] customers that PG&E
seeks recovery . . . . PG&E does not seek to earn a return on the
pass-through, but rather seeks to recover only the full cost it
incurs on behalf of these third parties.” Letter from PG&E to
David Boergers, Secretary, FERC (Nov. 9, 2000) at 6, JA 1206.
The pass-through tariff was calculated to reflect the percentage
that each Control Area Agreement customer contributed to the
relevant portion of the Grid Management Charge. The
customers were therefore billed for a portion of the Control Area
Services charge based on the “[c]ustomer’s monthly Gross
Load” and the Market Operations charge was billed based on the
customers “total purchases and sales of Ancillary Services,
Supplemental Energy, and Imbalance Energy.” Schedule 1,
PG&E’s GMC Pass-Through Tariff, JA 1210.
Several parties, including the petitioners in this case,
objected to the structure of the Grid Management Charge and
pass-through tariff. In May 2003, the Commission addressed
objections filed by affected parties to the Initial Decision of an
Administrative Law Judge (“ALJ”) approving the charge and
tariff. Cal. Indep. Sys. Operator Corp., 103 F.E.R.C. ¶ 61,114
at 61,352 (2003) (“Opinion No. 463”) (reviewing Cal. Indep.
Sys. Operator Corp., 99 F.E.R.C. ¶ 63,020 at 65,068 (2002)
(“Initial Decision”)). Among the issues addressed were: “the
assessment of the Control Area Service charge based on control
area gross load”; “the assessment of the charge to retail behind-
the-meter load”; and “whether PG&E’s [pass-through tariff]
passes through the costs of a new service providing new benefits
to the [Control Area Agreement] customers.” Id. at 61,353.
The Commission upheld the decision of the ALJ that gross
load allocation of the Control Area Services charge did not
violate cost causation principles. Several parties had argued to
the ALJ that “allocation of [Control Area Services] charges
based on [gross load] violates the Commission’s cost causation
8
principles because it includes behind-the-meter loads which do
not ‘use’ the ISO Controlled Grid.” Initial Decision, 99
F.E.R.C. at 65,109 (footnote omitted). The phrase “behind-the-
meter load” was defined by the ALJ to
refer to circumstances in which retail Loads of an entity and
the Generation from which that entity serves the Loads are
located on the same side of the meter at the interconnection
between the ISO Controlled Grid and the transmission or
distribution facilities of the entity. Parties have
denominated these circumstances as “wholesale behind-the-
meter.” It may also refer to circumstances in which a Load
is served by a Generator located on the side of the retail
meter between the Load and the ISO Controlled Grid or
between the Load and the distribution system of a [Utility
Distribution Company]. Parties have denominated these
circumstances as “retail behind-the-meter.”
Id. at 65,109 n.66 (citations omitted).
The ALJ rejected this argument on the ground that “both
‘cost causation’ and ‘benefits received’ are appropriate
considerations in determining whether the ISO’s [Control Area
Services] charge is ‘just and reasonable.’” Id. at 65,109. Where
an ISO has taken over the transmission grid, “all users of the
regional grid will [benefit] when that grid is operated and
planned by a single regional entity”; in that circumstance, it was
appropriate for “[a]ll customers using that grid [to] share in all
the costs of the grid, because they all benefit.” Id. (quoting
Midwest Indep. Sys. Operator, Inc., 98 F.E.R.C. ¶ 61,141 at
61,408, 61,412 (2002) (“Opinion No. 453-A”)). Citing
testimony from several witnesses, the ALJ concluded that
Control Area Services are “provid[ed] on behalf of all Load
within the ISO Control Area” and that “all load is wholly
dependent on the performance of these Control Area Services,
without which no load-serving entity, whether self-served,
behind-the-meter, or whatever, could operate.” Id. at 65,110.
9
The Commission affirmed the Initial Decision on this issue,
citing language from its decision in Opinion No. 453-A in which
the “Commission established that the benefits received by loads
served through non-grid facilities justified the allocation of costs
to those loads.” Opinion No. 463, 103 F.E.R.C. at 61,357 (citing
Opinion No. 453-A, 98 F.E.R.C. at 61,412).
While, in general, the Commission agreed that gross load
was an acceptable basis for allocating the Control Area Services
charge, it found that
the judge cast too wide a net with the gross load approach
in one respect. Customers with behind-the-meter
generation who primarily rely on that generation to meet
their energy needs have made a convincing argument that
use of gross load results in this customer class being
allocated too great a share of [Control Area Services] costs.
To take into account the more limited impact such
customers have on the ISO’s grid, the Commission finds
that they should be allocated [Control Area Services] costs
on the basis of their highest monthly demand placed on the
ISO’s grid, rather than on gross load. In this manner, their
more limited dependence on the ISO grid will be reflected
in their allocation of the [Control Area Services] costs.
Customers eligible for such treatment are those with
generators with a 50 percent or greater capacity factor.44
____________
44
Capacity factor is the ratio of the average load or output
of a generator for a given time period to the capacity rating
of the generator.
Id. The Commission agreed with the ALJ’s decision that retail
and wholesale generators should be treated similarly, noting that
the gross load allocation “exemption applies . . . whether the
behind-the-meter generation is wholesale or retail.” Id. at
61,358.
10
The Commission then turned to objections that had been
raised against the PG&E pass-through tariff. Objectors
complained that the pass-through tariff amounted to a change in
existing contracts for Control Area Agreement customers,
thereby “run[ning] afoul of the Commission’s longstanding
policy not to abrogate existing contracts in the context of
industry restructure.” Id. at 61,360. Objectors also complained
that the tariff violates the Mobile-Sierra doctrine, under which
“a utility cannot unilaterally file a new rate . . . to supersede the
agreed-upon rate” in an existing contract. Id. (quotation marks
and emphasis omitted).
The Commission rejected these arguments, finding that “the
existing [Control Area Agreements] are not being modified in
any manner, so that the agreed-upon rate for PG&E’s [Control
Area Agreement] services is not being superseded. Rather . . .
these customers of PG&E are receiving a new and different
service in addition to the service they already receive under the
Control Area Agreements.” Id. In analyzing the Control Area
Services component of the Grid Management Charge (and
therefore the pass-through tariff) the Commission addressed the
argument that the pass-through tariff does not represent “new or
different service ‘above and beyond’ what [the Control Area
Agreement customers] were provided by PG&E in its former
guise as a vertically-integrated utility.” The Commission found
that:
[T]here are indeed distinct services that are performed by
the ISO in its role as control area operator for which it is
billing PG&E. These include performing operational
studies, system security analyses, transmission maintenance
standards, [and] system planning to ensure overall
reliability. Of course, PG&E formerly provided to the
[Control Area Agreement] customers all the necessary
services required for the safe and reliable operation of a
high voltage electric transmission system. Accordingly, the
11
rate schedules for each of the [Control Area Agreements]
defined the extent of PG&E’s duties and responsibilities for
each customer. PG&E’s scheduling and scheduling-like
activities derived from the fact that PG&E was both a
transmission service provider and the control area operator.
Now, however, the ISO is the control area operator for the
former control area of PG&E (as well as the former control
areas of other utilities) and has the responsibility to provide
the [Control Area Agreement] customers access to the ISO
controlled-grid. Consistent with its obligations as a control
area operator, the ISO operates a real time Imbalance
Energy market to ensure that all generation and all load
within the control area are balanced on a
moment-to-moment basis . . . . [T]he ISO is responsible for
arranging operating reserves, scheduling interchange and
maintaining power flows within established operating
limits, and providing adequate contribution to
interconnection frequency regulation, while PG&E’s role is
now to coordinate with the ISO on load scheduling and
real-time operations, so that the [Control Area Agreement]
customers gain access to the grid necessary to satisfy the
requirements under their contracts.
Id. at 61,361-62 (footnotes omitted).
The Commission reversed the finding of the ALJ that the
Market Operations charge did not represent new services.
PG&E challenged the finding of the ALJ, arguing that “there are
now competitive markets established for ancillary services and
imbalance energy, as opposed to the pre-ISO era when PG&E
had no such markets and managed ancillary services as a
vertically integrated utility.” Id. at 61,362. The Commission
agreed, finding that, “[a]s with the [Control Area Services], we
find that there is no duplication of function of activity between
PG&E and the ISO, because the scheduling activities that PG&E
performs under the [Control Area Agreements] is unrelated to
12
the ISO activities that give rise to the [Market Operations]
component of the [Grid Management Charge].” Id. The
Commission also acknowledged that “[m]any [Control Area
Agreement] customers argue that they should not be assessed
the [Market Operations] component of the [Grid Management
Charge] because they can self-provide certain services.” Id.
The Commission found that the Market Operations charge
would only be assessed “for accessing the ISO-controlled grid
to support transmission service” and, therefore, the Market
Operations charge did not violate cost-causation principles. Id.
Upon requests for rehearing, the Commission reconsidered
its view of the exemption to the gross load allocation that it had
crafted in Opinion No. 463, finding that “this exception is not
supported by record evidence.” Cal. Indep. Sys. Operator
Corp., 106 F.E.R.C. ¶ 61,032 at 61,106, 61,111 (2004)
(“Opinion 463-A”). The Commission, however, continued to
“believe that certain behind the meter generators should be
subject to an exception,” and therefore adopted a new standard:
In light of the nature of the [Control Area Services] charges,
in particular expenses incurred for the continued planning
of operation of the transmission grid, it appears appropriate
that generators which are not modeled by the ISO in its
regular performance of transmission planning and operation
should be exempted from the [control area gross load]
charge. That is, those generators that will not cause the ISO
to incur administrative or operating expenses should,
therefore, have the load exempted from the [Control Area
Services] charge.
Id.
Several parties again petitioned for rehearing, and the
Commission found that those petitions “have made clear that
questions concerning the exemption, as well as the manner in
which it would be administered, present issues of material fact
13
that cannot be resolved based on the record before us.” Cal.
Indep. Sys. Operator Corp., 109 F.E.R.C. ¶ 61,162 at 61,772,
61,774 (2004). The Commission therefore ordered a second
evidentiary hearing on the question of the exemption. Id.
After conducting a second hearing, the ALJ released her
findings on the exemption to the Control Area Gross Load
allocation. The ALJ explained how the California ISO “models”
generators:
[I]t is necessary to keep in mind that the ISO does not
actually model generating units. Instead, it adopts the
power flow models, including the representations of
generating units, which are developed by the
investor-owned [Participating Transmission Operators]. A
model is a quantitative representation of the facilities that
constitute the grid, and their physical limitations. . . . The
ISO has explained that while it does not model generating
units per se, it does use the models provided to it by the
[Participating Transmissions Operators] to conduct studies
that examine the effects of different conditions under which
the transmission system may have to operate and to
determine the effects of the conditions on the transmission
system.
Cal. Indep. Sys. Operator Corp., 111 F.E.R.C. ¶ 63,008 at
65,044, 65,052-53 (2005) (“Initial Decision II”) (footnotes
omitted).
The ALJ also recited the ISO’s view that “the purpose of
the [Control Area Services] charge” is not “to recover the costs
of modeling generating units”; rather “the criterion of whether
a generating unit was modeled . . . is an objective criterion used
as a surrogate to identify load with a more limited []dependence
on the ISO’s control area services.” Id. at 65,049. The ALJ also
described the kinds of behind-the-meter load and generation that
must be modeled:
14
(1) behind-the-meter generation that may deliver excess
energy to the transmission system in the wholesale market
arena; (2) behind-the-meter load serviced by the
behind-the-meter generation that would remain connected
and continue to draw power from the transmission system
in the event the behind-the-meter generation tripped or was
curtailed; and (3) behind-the-meter generation that is of
such size, nature, and character or connected at a critical
point within the transmission system such that the
performance of the transmission system with respect to
transient stability, voltage collapse, local area power
quality, fault current contribution or coordination of
protective devices.
Id. at 65,056.
In Opinion No. 463-B, the Commission adopted many of
the factual findings of the ALJ, and clarified the nature and
scope of the “modeling” exemption. The Commission adopted
the ALJ’s definition of a model as “a quantitative representation
of the facilities that constitute the grid, and their physical
limitations.” Cal. Indep. Sys. Operator Corp., 113 F.E.R.C.
¶ 61,135 at 61,536, 61,546 (2005) (“Opinion No. 463-B”)
(quotation marks omitted). The Commission further cited
testimony from an expert witness that a “model” as used in the
behind-the-meter exemption is a “numerical representation of
the physical equipment, and its limits, that comprises the electric
grid, the interrelations between the equipment (that is, how the
pieces are ‘wired’ together), and the information on the real
world limitations of such equipment.” Id.
The Commission agreed with the ALJ that the “ISO does
not itself create models of generating units, but uses those
provided by the Participating Transmission Owners to conduct
studies concerning transmission planning and operation.” Id.
The Commission, however, “reject[ed] the contention . . . that
because the ISO does not actually construct the base-case
15
models . . . it does not ‘model’ generation. The important fact
is that the generators were included in the models which the ISO
examines and on which it bases its studies. . . . [T]he relevant
factor [is] whether a particular Generating Unit was modeled,
and not who modeled the Generating Unit in question.” Id.
(quotation marks omitted).
The Commission also clarified that the intent of the
“modeling” exemption was to “identify[] and defin[e] the subset
of behind-the-meter generators which incur no Control Area
Services costs (or only de minimis costs).” Id. at 61,544.
Behind-the-meter generation was defined further to describe
“situations in which a Load’s electrical consumption cannot be
distinguished from a Generating Unit’s simultaneous production
of electricity, because both are measured with only one meter.”
Id. at 61,544-45 (quotation marks omitted). The Commission
described the intended scope of the exemption from the gross
load allocation of the Control Area Services charge to be
“extremely limited”:
A hypothetical situation which we believed indicated the
need for an exemption was a behind-the-meter 10 MW
generator which served its own load except for two weeks
a year when it was off-line for maintenance. . . . [T]he great
majority of the time, such a generator and an equivalent
amount of behind-the-meter load would not [be] seen by the
ISO, and not receive any [Control Area Services]. . . . [As
a witness explained:
The ISO] admits that it knows very little about the
behind-the-meter load served by on-site generation, it
is hard for me to understand how such load causes the
[]ISO to do any work. When such loads are not served
by on-site generation, that is, when they are served
over the utility’s transmission and distribution
facilities, is when they cause the []ISO to do work,
such as ensuring operating reserves; but at these times,
16
the []ISO sees these loads and appropriately assesses
them the [Control Area Services] charge.
It is the generators serving this load unseen by the ISO – for
which the ISO obviously does not provide Control Area
Services – for which the Commission has been trying to
craft an exemption.
Id. at 61,545 (footnote omitted).
Finally, the Commission found that the record showed that
“generation which is not modeled does not incur Control Area
Services costs.” Id. at 61,547. Relying on the testimony of an
ISO witness, the Commission found that
for on-site behind-the-meter generation, the ISO has no
information and must make estimates to figure gross load
allocation. Thus, while there is no specific quantification
in the record concerning Control Area Services costs for
this behind-the-meter generation, there is evidence that the
ISO does not “see” this generation . . . and “does no work”
for it, except when it is actually using the ISO grid. . . .
[T]here is indeed a small subset of generators for which the
ISO incurs no Control Area Services costs whatsoever.
Id. (footnote omitted). Based on these findings, the Commission
found that the “modeling” exemption was justified.
The Commission issued a final opinion denying requests for
rehearing of Opinion No. 463-B. The Commission maintained
that the standard that it developed for the behind-the-meter
exemption – allowing generators that are not “modeled” by the
ISO to avoid paying the Control Area Services charge on a gross
load basis – was justified. The Commission maintained “that
while the mechanics of the exemption from allocation of
[Control Area Services] costs based on [gross load] has evolved
in the course of this proceeding as the factual record has
developed, the Commission has held firm to its view that
17
generators that will not cause the ISO to incur expenses should
have their load exempted from [Control Area Services]
charges.” Cal. Indep. Sys. Operator Corp., 116 F.E.R.C.
¶ 61,224 at 61,913, 61,916 (2006) (“Opinion 463-C”).
Reviewing challenges to the standard that it had adopted, the
Commission concluded that it was justified and that no party had
raised any issue requiring a rehearing. The Commission
therefore denied all rehearing requests in all respects. Id. at
61,919.
After this decision, the Existing Customers petitioned this
court for review of Opinion 463-C and prior decisions of the
Commission leading up to that opinion. CoGen, however,
sought FERC rehearing of Opinion No. 463-C. The
Commission summarily dismissed CoGen’s request for a
rehearing, stating that “[t]he Commission does not allow
rehearing of an order denying rehearing.” Cal. Indep. Sys.
Operator Corp., 118 F.E.R.C. ¶ 61,061 at 61,317, 61,319
(2007). CoGen then petitioned this court for review of this final
order denying a rehearing of Opinion No. 463-C, and the prior
opinions.
II. ANALYSIS
A. Standard of Review
We review the Commission’s orders “under the familiar
arbitrary and capricious standard.” Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004). “We
abide by the Commission’s factual findings if they are supported
by substantial evidence, and . . . affirm the Commission’s orders
so long as FERC examined the relevant data and articulated a
rational connection between the facts found and the choice
made. When FERC’s orders concern ratemaking, we are
particularly deferential to the Commission’s expertise.” Id.
(quotation marks, citations, and alterations omitted).
18
B. CoGen’s Petition Is Untimely
Under 16 U.S.C. § 825l(b):
[A] party . . . aggrieved by an order issued by the
Commission . . . may obtain a review of such order in the
United States Court of Appeals . . . by filing in such court,
within sixty days after the order of the Commission upon
the application for rehearing, a written petition preying that
the order of the Commission be modified or set aside.
This provision establishes a jurisdictional time bar on petitions
for review of FERC orders. See City of Batavia v. FERC, 672
F.2d 64, 72-73 (D.C. Cir. 1982). Therefore, because “[s]tatutory
jurisdictional requirements . . . are not mere technicalities that
can be brushed aside by a court,” Williston Basin Interstate
Pipeline Co. v. FERC, 475 F.3d 330, 336 (D.C. Cir. 2006), we
must parse the record with care to determine whether CoGen’s
petition for review is timely.
The Commission’s orders became ripe for judicial review
with Opinion No. 463-C, which denied all of the parties’
requests for rehearing of Opinion 463-B in their entirety. The
Existing Customers sought review of Opinion No. 463-B and
Opinion No. 463-C after the denial of the request for rehearing.
CoGen, however, filed a request for rehearing of Opinion 463-C
before the Commission, a request that was denied in a summary
decision, and now seeks review of the later order.
CoGen argues that Opinion No. 463-C “did not simply deny
rehearing. . . . Instead, Opinion 463-C set forth a [new] standard
for exemption from the [Control Area Services] charge.” Reply
Br. of Cogeneration Association at 4. CoGen finds this new
standard in a paragraph in Opinion No. 463-C in which the
Commission defends the modeling standard for the exemption
to the gross load allocation against criticism that it violates cost
causation principles:
19
The Commission previously noted that based on cost-
causation principles, certain customers should be exempted
from the allocation of [Control Area Services] costs, and
upon further investigation the Commission refined that
exception to better match the specifics of cost-causation in
this proceeding. The [California] ISO incurs administrative
costs in conducting such activities as transmission planning
studies and transmission operation studies. Accordingly,
we disagree with [the] assertion that there is no cause and
effect relationship between modeled generation and
[California] ISO’s administrative expenses. Additionally,
[Participating Transmission Operators] historically have
been the source of the transmission and generation data
required to conduct such studies and analyses. To the
extent that generators are included in [Participating
Transmission Operator] studies and/or models and the ISO
subsequently receives the information, the ISO will decide
whether that information is relevant and useful in
conducting its various studies and in modeling the
transmission system. If the ISO decides that the
information regarding behind-the-meter generators is
relevant to its studies and system modeling, then those
generators are ineligible for the exemption because they
are significant for study and modeling purposes and thus
ultimately relate to administrative costs incurred by the
ISO. We therefore will deny rehearing requests of [CoGen]
and SMUD on this issue.
116 F.E.R.C. at 61,917 (footnote omitted) (emphasis added).
However, this paragraph simply does not do the work that
CoGen wants it to do. Nothing in Opinion No. 463-C changes
the standard given in Opinion No. 463-B. Opinion No. 463-C
simply offers further justification for why the standard is
appropriate and consistent with FERC’s cost-causation
principles. The standard, that generators that are not “modeled”
by the ISO – i.e., generators on which the Participating
20
Transmission Operators are not required to provide data to the
ISO – are exempt from the gross load allocation, remained the
same. It was the same before and after Opinion No. 463-C. In
the language at issue, the Commission simply reiterated its
argument – which it had offered many times before – that
modeling was an appropriate proxy for costs incurred. That the
Commission used slightly different words to do so does not
make Opinion No. 463-C a separate order requiring a request
for rehearing.
In order for petitioners to preserve their rights to judicial
review under 16 U.S.C. § 825l(b), they must file a request for
rehearing of a challenged order with FERC “unless there is
reasonable ground for failure so to do.” Allegheny Power v.
FERC, 437 F.3d 1215, 1220 (D.C. Cir. 2006) (quoting statute).
We clarified the circumstances under which a complainant need
not request rehearing:
[W]e conclude that [the Federal Power Act] does require an
application for rehearing of an order on rehearing when the
later order modifies the results of the earlier one in a
significant way, raising objections to the rehearing order
that are substantially different from those raised against the
original one.
Town of Norwood, Mass. v. FERC, 906 F.2d 772, 775 (D.C. Cir.
1990). In Allegheny Power, we further clarified that the Act
“requires a second petition only when the result is different; a
petitioner need not file a second petition ‘when the outcome had
not been changed but the Commission had supplied a new
improved rationale.’” 437 F.3d at 1222 (quoting Cal. Dep’t of
Water Res. v. FERC, 306 F.3d 1121, 1226 (D.C. Cir. 2002))
(brackets omitted).
These cases describe the conditions under which a request
for rehearing is necessary to preserve challenges on objections
to a Commission order, but they also indicate when a challenge
21
is ripe for judicial review. When a petition for rehearing is not
necessary – i.e., when a rehearing has been denied in its entirety
with no substantive modification in the order – the case is ripe
for judicial review and the clock on the jurisdictional time-bar
starts ticking. Cf. Williston Basin, 475 F.3d at 335 (holding
that, under the Natural Gas Act, court had no jurisdiction over
petition filed more than 60 days after the FERC order “of which
[petitioner] now seeks review” where request for rehearing was
not timely filed). CoGen was required to file a petition for
review within 60 days of FERC’s issuance of Opinion No. 463-
C. It is quite clear that Opinion No. 463-C provided an
adequate basis for a petition for judicial review. Because
Opinion No. 463-C was simply a denial of rehearing and did
not, as the CoGen argues, create a new standard for the
exemption to the gross load allocation of the Control Area
Services charge, CoGen’s petition for review is time barred.
Accordingly, we have no jurisdiction over the challenges raised
by CoGen.
C. The Grid Management Charge and Pass-Through Tariff
Are for New Services
The Existing Customers argue that the Grid Management
Charge and the pass-through tariff violate the Mobile-Sierra
doctrine because they amount to an alteration of an existing
contract. The Mobile-Sierra doctrine arises from two Supreme
Court decisions, United Gas Pipe Line Co. v. Mobile Gas Serv.
Corp., 350 U.S. 332 (1956), and Fed. Power Comm’n v. Sierra
Pacific Power Co., 350 U.S. 348 (1956). We have described
the doctrine as follows:
Under the well-settled and oft-invoked Mobile-Sierra
doctrine, utility providers that negotiate fixed-rate contracts
with their customers may, as part of that negotiation,
voluntarily relinquish some of the rate-filing freedom to
which they are otherwise entitled under Section 205 of the
[Federal Power Act]. Under such contracts, utility
22
providers are prohibited from filing a new rate for services
currently provided (and therefore subject to) the negotiated
contract rate. FERC is similarly prohibited from
modifying the contract rate . . . except where the
modification is both required by the public interest and
upon a showing that the changes are just, reasonable, and
nondiscriminatory.
East Kentucky, 489 F.3d at 1309 (quotation marks, brackets,
footnotes, and citations omitted).
However, where “a new rate” is intended “to recover the
costs of new benefits and services,” “[t]he Mobile-Sierra
doctrine, powerful though it may be where it applies, is not
implicated.” Id. The question that we must address, then, is
whether the Control Area Services charge and Market
Operations charge are for new services provided by the ISO for
the benefit of the Existing Customers among others. If they
cover new services, then the Mobile-Sierra doctrine does not
apply and the Commission was justified in upholding the Grid
Management Charge and pass-through tariff. In Midwest ISO
and East Kentucky, we addressed very similar questions relating
to the Midwest ISO, and found that the ISO provided new
services to customers with preexisting contracts with formerly
vertically integrated utilities. Applying those cases to the
California ISO, we find that the ISO similarly provides new
services. Therefore, the Mobile-Sierra doctrine is inapplicable.
In Midwest ISO, we reviewed a decision by the
Commission concerning the allocation of the Midwest ISO’s
administrative costs. Midwest ISO, 373 F.3d at 1366-67. The
Commission had required the “ISO Cost Adder, [which] was
designed to recover [Midwest ISO] administrative costs,” to be
applied to all loads in the system, including “bundled” and
“grandfathered load.” Id. When the Midwest ISO was created,
the participating transmission owners had obligations “to
provide bundled retail service (generation and transmission) to
23
consumers at rates frozen by state legislation, state regulatory
agencies, or legal settlements,” as well as “pre-existing bilateral
agreements with other utilities to provide wholesale
transmission service at fixed rates.” Id. at 1365. The owners
proposed that the Cost Adder be applied only to “new wholesale
and unbundled retail transmission,” id. at 1365-66, but first an
ALJ and then the Commission found that in order for the Cost
Adder to be “just and reasonable,” it had to apply to “bundled
retail loads or grandfathered loads,” because “[a]ll of the
Midwest ISO’s Participants’ transmission customers will
benefit” from the new system.” Id. at 1366-67.
We upheld the Commission’s determination finding that
“all transmission customers – bundled, unbundled,
grandfathered, whatever – benefit from the enhanced reliability
and security [Midwest ]ISO brings to the transmission grid.” Id.
at 1369-70. We also found that “benefits such as an overall
reduction in the costs of transmitting energy within the region
and large scale regional coordination and planning of
transmission would redound to all users of the transmission
grid.” Id. at 1371 (quotation marks omitted). Because all
transmission customers “draw benefits from being a part of the
[Midwest] ISO regional transmission system, FERC correctly
determined that they should share the cost of having an ISO.”
Id.
In East Kentucky, we addressed a follow-up issue. The
Cost Adder at issue in Midwest ISO was applied by the ISO to
the participating transmission owners; the question in East
Kentucky was whether the transmission owners could pass
through that charge to customers with preexisting contracts.
The Commission found that the owners could pass through the
cost of administering the ISO, because “the benefits brought by
the []ISO represent new services not previously provided under
. . . pre-ISO grandfathered contracts.” East Kentucky, 489 F.3d
at 1307 (quotation marks omitted). Those benefits included:
24
(1) independent and regional grid planning (as opposed to
utility-by-utility planning), (2) enhanced reliability, (3)
increased efficiency, (4) more effective management of
grid congestion to accommodate greater power flows, (5)
access to spot markets, and (6) price transparency to
facilitate bilateral contract formation.
Id. We concluded that the Commission “reasonably rested its
decision on this new services analysis and considered evidence
that the costs to be collected under [the new charge] are separate
and distinct from the costs collected under the grandfathered
agreements.” Id. at 1308 (quotation marks omitted).
Both Midwest ISO and East Kentucky show that regional
ISOs generate significant benefits for all customers of a
transmission system, including customers that had preexisting
contracts with formerly vertically-integrated utilities for all
services. East Kentucky clearly rejected the argument that
transmission contracts that provided for safe, reliable
transmission by a regional operator positively exclude new
services provided by an ISO. ISOs produce new benefits that
the vertically-integrated utilities did not; therefore, it is not
enough for the Existing Customers to point to their contracts
with these utilities and argue that the new system does not
provide them with any benefits that they had not contracted for
in prior years.
FERC made factual findings that the California ISO would
generate significant new services for PG&E’s existing
customers. In Opinion No. 463-A, the Commission noted that
the California ISO has brought about “‘massive’ and
‘fundamental changes’ in the manner in which electricity is sold
and distributed there, so that ‘the complexities of operating the
transmission system have increased exponentially.’” 106
F.E.R.C. at 61,111 (quoting witness). The Commission recited
some of the benefits of the ISO:
25
[B]y combining the pre-ISO control areas and eliminating
pancaked rates, the ISO operations allow greater access to
generation alternatives so that the ISO can provide
ancillary services to the existing transmission contracts in
the most cost-effective and efficient manner possible on a
broad regional basis. Regional planning and operation of
the combined ISO grid maximizes efficiencies when
compared to the pre-existing utility operations.
Consolidating scheduling maximizes transmission usage,
reduces ancillary service requirements and provides greater
reliability by allowing the operation of more facilities to
respond to contingencies.
Id. at 61,112.
The Commission also noted the creation of new market
opportunities, which in the long term will “result in an increased
supply of competing generation to load-serving entities . . .
leading to lower overall costs.” Id. These same new market
opportunities were credited by this court in Midwest ISO and
East Kentucky as lending support to the justification for a new
charge. The Commission further noted evidence provided by
PG&E that “the costs of the [Grid Management Charge]
passthrough were for the ISO’s service, and not the service
which PG&E has provided and continues to provide under”
existing contracts. Id. The Commission credited the testimony
of PG&E witness Mr. Bray:
Mr. Bray specifically explained that the “ISO performs
certain activities in its role of control area operator which
were not performed in the pre-ISO era.” He further stated
that the ISO’s new tasks had a direct impact on PG&E,
which “performs on behalf of each and every [Control Area
Agreement] customer as its ISO-certified Scheduling
Coordinator a new and unique function that it did not
provide to the [Control Area Agreement] customers prior
to the ISO.” He also distinguished the costs charged by
26
PG&E for services performed under the [Control Area
Agreements] from the costs that PG&E was passing
through to its [Control Area Agreement] customers by
means of the [pass-through tariff].
Id. (footnotes, brackets, and ellipses omitted). The Commission
additionally credited the testimony of PG&E witness Mr. King,
“who explained in detail the manner in which he analyzed the
company’s accounts to demonstrate that ‘no ISO costs billed to
PG&E for [the] ISO [Grid Management Charge] are included in
PG&E’s transmission operation and maintenance expense
accounts or the [Control Area Agreements].’” Id. (quoting
witness) (bracket omitted).
The petitioners fail in their attempts to rebut FERC’s
analysis. Petitioners argue that new market opportunities are
not a new benefit, but this contention is directly contrary to this
court’s findings in Midwest ISO and East Kentucky. Petitioners
also fail to address new efficiencies that are created by the
existence of a regional transmission grid. The best argument
presented by the petitioners is that, under the new regime,
PG&E has fewer responsibilities for “managing the Control
Area” and therefore fees that it collected for that role in the past
should be returned to customers. Br. for Western Area Power
Admin. at 45-46. The Commission addresses this argument in
two ways. First, the Commission credited PG&E’s testimony
that the new ISO arrangement creates additional burdens on
PG&E in its role as Scheduling Coordinator. More importantly,
the Commission has refuted the petitioners’ zero-sum argument
by noting that the new arrangement – while it may generate
long-term benefits – results in “exponential[]” increases in the
complexity of the system. Thus, it is not the case that there is
a one-for-one relationship such that each service that is now
done by the ISO means one less service provided by PG&E.
The point is that, together, PG&E and the ISO perform new and
better services for customers. The pass-through tariff is dollar-
27
for-dollar based on the Grid Management Charge, which itself
is the cost of starting up and operating the ISO. The customers
get the benefit of the new system and pay exactly the cost of the
new system.
In its first Initial Decision, the ALJ found that “PG&E has
failed to carry its burden of proof” to show that the Market
Operations charges were for new services “when those services
are being self-provided and not procured through the ISO
Markets.” 99 F.E.R.C. at 65,173. The Commission overruled
that finding, holding that the ISO is only “assessing charges to
the responsible [Scheduling Coordinator] for accessing the
ISO-controlled grid to support transmission service.” Opinion
No. 463, 103 F.E.R.C. at 61,362. The Commission further
clarified its position in Opinion No. 463-A, stating that “the
[Market Operations] charge is only assessed on a Scheduling
Coordinator when it procures such services through the ISO
markets. The tariff further provides that a Scheduling
Coordinator’s responsibility for these costs is reduced by other,
self-provided ancillary services.” 106 F.E.R.C. at 61,114
(footnote omitted). Thus, the Commission argues, “the parties’
claim of being charged twice for the same service cannot be
sustained.” Id.
The Commission’s finding on the Market Operations
charge is based on substantial evidence and it is not arbitrary or
capricious. The Existing Customers’ complaint is premised on
their view that, when they self-provide ancillary services, they
should not be charged a Market Operations charge because they
are not availing themselves of any Market Operations services.
But, as the Commission has noted, this is a misplaced concern.
The billing determinant for the Market Operations charge is
“the proportion of a given [Scheduling Coordinator’s] total
purchase and sales of Ancillary Services, Supplemental Energy,
and Imbalance Energy . . . to the total purchases and sales of all
[Scheduling Coordinators].” PG&E – in its role as a Scheduling
28
Coordinator – then passes on that charge to its customers, based
on “total purchases and sales of Ancillary Services,
Supplemental Energy, and Imbalance Energy” to its customers.
FERC, both in the administrative record and in oral arguments
to this court, has indicated that all self-provision of ancillary
services will be accounted for, and that the Market Operations
charge for all existing customers will be reduced accordingly.
The Existing Customers have shown nothing to the contrary.
The Commission’s findings therefore survive scrutiny under the
deferential arbitrary and capricious standard of review.
Finally, we do not address the arguments raised by the
Existing Customers that provisions of their contracts with
PG&E either expressly forbid PG&E from charging for “new
services” or provide for specific consultive procedures before
any such charges may be implemented. The contract provisions
cited by petitioners do not facially support the assertions they
now advance. Furthermore, petitioners have failed to show that
they properly raised these precise contract claims with FERC so
as to preserve them for judicial review.
Because the ISO provides new services, the Grid
Management Charge and PG&E’s pass-through of that charge
to the Existing Customers do not violate the Mobil-Sierra
doctrine. The Commissions factual findings on this matter
relied on substantial evidence, and its decision to approve the
charge and pass-through was not arbitrary or capricious.
D. The “Modeling” Exemption to the Gross Load Allocation
of the Control Area Services Charge Was Not Arbitrary
The Commission found that a gross load allocation for the
Control Area Services charge was appropriate. The Control
Area Services charge “represent[s] the ISO’s administrative
costs of providing essential services necessary to ensure the
safe, reliable operation of the transmission grid and the dispatch
of bulk power supplies.” Opinion No. 463, 103 F.E.R.C. at
29
61,356 (quotation marks and brackets omitted). The
Commission found that allocation of this charge on a gross load
basis did not violate cost-causation principles, because “the
[Control Area Services] in question are not and could not be
self-provided” and “all load is wholly dependent on the
performance of [Control Area Services], without which no load
serving entity could operate. These services cannot . . . be
duplicated by [Scheduling Coordinators] or other parties
operating in a smaller service area within the ISO’s footprint.”
Id. at 61,357.
Focusing on the “behind-the-meter” exemption to the gross
load allocation, Br. for Western Area Power Admin. at 55-56,
petitioners argue that the Commission was correct to carve out
an exemption to the gross load allocation for certain types of
generation, but that the final exemption adopted by the
Commission was “illogical” and arbitrary, id. at 58. Petitioners
contend that because FERC has created an exemption for
generators that do not make use of the ISO controlled grid, it
cannot exempt “only some of [that] load.” Id. at 57. Petitioners
claim that there are other types of generation “for which
[California] ISO does not have to plan and over which it is not
responsible” that do not fall within the exemption. Id. at 60.
Two examples are cited by petitioners: electricity supplied to
SMUD from the Western Area Power Administration “over
non-[]ISO grid facilities” and electricity that flows within a
“[Metered Subsystem] bubble.” Id. at 59. A Metered
Subsystem bubble, according to petitioners, is an “area . . .
served by an [existing customer] relying, in part or in whole, on
transmission that is outside the control of [the] ISO and where
the [existing customer] is wholly responsible for all load and
generation.” Id. at x. Petitioners complain that the Commission
failed to explain “why only ‘behind-the-meter-generation’ so
defined would reduce the burden on the []ISO grid.” Id. at 59.
30
The arbitrary and capricious standard structures our review
of the Commission’s adherence to the cost-causation principle.
As we stated in Midwest ISO, the cost-causation principle
requires
that all approved rates reflect to some degree the costs
actually caused by the customer who must pay them. Not
surprisingly, we evaluate compliance with this
unremarkable principle by comparing the costs assessed
against a party to the burdens imposed or benefits drawn by
that party. Also not surprisingly, we have never required
a ratemaking agency to allocate costs with exacting
precision. It is enough, given the standard of review under
the APA, that the cost allocation mechanism not be
“arbitrary or capricious” in light of the burdens imposed or
benefits received.
Midwest ISO, 373 F.3d at 1368-69 (quotation marks, brackets,
and citations omitted). “FERC is not bound to reject any rate
mechanism that tracks the cost-causation principle less than
perfectly.” Sithe/Independence Power Partners, L.P. v. FERC,
285 F.3d 1, 5 (D.C. Cir. 2002).
The Commission decision does not fail arbitrary and
capricious review. On several occasions, FERC has given
adequate explanations for why it arrived at the “modeling”
standard for the gross load exemption. In Opinion 463-B,
FERC reviewed the findings of the ALJ and drew several
factual conclusions that support the behind-the-meter
exemption:
[T]he Commission hereby finds that: (1) the ISO, using
models provided by the Participating Transmission
Owners, conducted studies concerning transmission
planning and operation during the locked-in period; (2) the
generating units included in these studies were modeled by
the ISO during the [relevant] period, and thus the ISO
31
incurred costs recovered by the ISO’s Control Area
Services charge; [and] (3) there is record evidence that
unmodeled behind-the-meter generation did not impose
Control Area Services costs because it was not taken into
account by the ISO’s transmission planning and operations
....
113 F.E.R.C. at 61,544. In Opinion 463-C, the Commission
explained succinctly that when “the ISO decides that the
information regarding . . . generators is relevant to its studies
and system modeling . . . they are significant for study and
modeling purposes and thus ultimately relate to administrative
costs incurred by the ISO.” 116 F.E.R.C. at 61,917.
It is worth noting that the exemption as currently crafted
does not benefit the ISO or PG&E. The administrative costs
incurred by the ISO that the Control Area Services charge is
meant to recoup will be the same with the exemption in its
current form, with a broader exemption, or with no exemption
at all. The only question is who will ultimately pay, an
allocation question that pits customers against each other, but
not ultimately against the ISO or PG&E. Any Control Area
Services charge that is not paid by petitioners in this case will
simply be paid by another customer. The current exemption is
reasonable and relatively straightforward to administer, while
other alternatives would be much more difficult to administer.
Petitioners complain that the exemption is not perfect, and
that the costs of the ISO are not shared precisely according to
the users that place the most strain on the system. That may be
true, but the Commission has articulated a reasoned explanation
for carving out the exemption that it did. And the exemption
indisputably excludes at least some of the relevant generators,
and it is convenient to administer. The Commission settled on
the modeling exemption only after receiving extensive public
comments and carefully considering a number of possibilities.
Neither the agency’s deliberative process nor its final decision
32
fails scrutiny under the arbitrary and capricious standard of
review. Indeed, it is noteworthy that petitioners have not
proposed any alternatives that are clearly better.
III. CONCLUSION
For the reasons discussed above, we lack jurisdiction to
address CoGen’s petition for review, and we deny the Existing
Customers’ petition for review for want of merit.