Document ID: s3://data.kl3m.ai/documents/govinfo/USCOURTS/USCOURTS-caDC-06-01371/USCOURTS-caDC-06-01371-0/pdf.json

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

Document Text:

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

USCA Case #06-1371 Document #1114305 Filed: 05/02/2008 Page 1 of 32
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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

USCA Case #06-1371 Document #1114305 Filed: 05/02/2008 Page 2 of 32
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Producers and Users Coalition (together “CoGen”). The

petitioners argue that the Commission acted arbitrarily and

capriciously in approving fees that violated FERC costcausation 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. . . .

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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.

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 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

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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 InterZonal 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

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“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 behindthe-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

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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-themeter 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-themeter.” 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.

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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.

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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

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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

USCA Case #06-1371 Document #1114305 Filed: 05/02/2008 Page 11 of 32
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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

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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:

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(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

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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,

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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

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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).

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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:

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The Commission previously noted that based on costcausation 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

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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

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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

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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

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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:

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(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:

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[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

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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 dollarUSCA Case #06-1371 Document #1114305 Filed: 05/02/2008 Page 26 of 32
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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

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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

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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.

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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

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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

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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.

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