United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued March 16, 2007 Decided June 15, 2007
No. 06-1003
EAST KENTUCKY POWER COOPERATIVE, INC.,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT
DAIRYLAND POWER COOPERATIVE, ET AL.,
INTERVENORS
On Petition for Review of Orders of the
Federal Energy Regulatory Commission
Alan I. Robbins argued the cause for petitioner. With
him on the briefs was Elizabeth B. Teuwen.
Larissa A. Shamraj and Jeffrey L. Landsman were on the
brief for intervenors Midwest Municipal Transmission Group
and Dairyland Power Cooperative in support of petitioner.
Robert A. Jablon entered an appearance.
Jeffery S. Dennis, Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With him on the
brief were John S. Moot, General Counsel, and Robert H.
2
Solomon, Solicitor. Judith A. Albert, Attorney, entered an
appearance.
Michael E. Small argued the cause for intervenors
Midwest ISO Transmission Owners in support of respondents.
With him on the briefs was Arnold B. Podgorsky. Andrew T.
Swers and Wendy N. Reed entered appearances.
Before: GRIFFITH, Circuit Judge, and EDWARDS and
WILLIAMS, Senior Circuit Judges.
Opinion for the Court filed by Circuit Judge GRIFFITH.
GRIFFITH, Circuit Judge: In petition for review,
customers of a public utility challenge a decision of the Federal
Energy Regulatory Commission (“FERC” or the “Commission”)
that approved new charges for electricity service. Petitioners
argue that the Commission’s decision to approve the charges
was arbitrary and capricious because the services for which the
charges were assessed are already covered in existing contracts
that shield them from new charges unless they are for “new
services.” Petitioners further argue that the Commission did not
engage in reasoned decisionmaking because its conclusion is
inconsistent with previous determinations it has made with
regard to the same charges. FERC responds that the services for
which new charges are assessed are “new services,” and
distinguishes its conclusions in previous proceedings by arguing
that the utility owners (intervenors in support of FERC) had
failed to demonstrate that the services were not already covered
by existing rates.
Under our particularly deferential standard of review for
the Commission's decisionmaking, we conclude that FERC
considered substantial evidence that the proposed tariff was
assessed to collect charges associated with new services and that
3
its decision to approve that tariff was rational. We also find that
FERC’s conclusion was not inconsistent with its prior
determinations because, as the Commission has explained, new
evidence was before it. We therefore deny the petition.
I.
In 1996, FERC introduced electric utility companies
operating under its authority to a brave new regulatory world
with its vanguard Order No. 888, whose aspirational title made
up in optimism what it lacked in literary flair. See Promoting
Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities,
FERC Stats. & Regs. ¶ 31,036, 61 Fed. Reg. 21,540 (1996)
(“Order No. 888”). Promulgated in response to the anti-
competitive effects of vertical integration and, in particular, the
unlawful practice of some electric utilities to provide third-party
wholesalers of electric power inferior access or no access at all
to their transmission networks, see Order No. 888 at 31,682-84,
this remedial order required the “functional unbundling” of
wholesale generation and transmission services. Id. at 31,654. 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. Both would deal with one another at
arm's length. Utilities were required to state separate rates for
their generation, transmission, and ancillary services and, when
providing any of those services for themselves (or their
affiliates), do so under the same terms and with the same priority
as those available to other market participants. The purpose was
to prevent a utility from gaining special access to service or
special price deals by virtue of its integration of 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. By consolidating control (but not
ownership) of the now unbundled transmission services, FERC
hoped to preserve the efficiencies produced by vertical
integration while forestalling its anti-competitive effects.
Wholesale competition would be encouraged over broad
geographic areas, Order No. 888 at 31,730-32, see also Public
Util. Dist. No. 1 of Snohomish County v. FERC, 272 F.3d 607,
610-11 (D.C. Cir. 2001), while operational redundancies would
be reduced or eliminated. Regional transmission reliability
would also be enhanced. See Order No. 888 at 31,730-32.
Familiar with the influence on utilities of the powerful
incentives to avoid regulations that limit monopolistic
advantages, 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 Independent System Operator (“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. See id. at 31,654, 31,730-32 (announcing
certain principles to guide further consideration of ISO
proposals).
Predictably, not all shared FERC’s vision of how energy
markets should function. Most utilities declined the
Commission’s invitation to voluntarily embrace a future of
robust competition in the wholesale electricity market. And
because FERC had required only unbundling, and not the
formation of RTOs, utility companies were free to sit out that
particular dance. FERC, anxious to see greater participation than
had been achieved through mere suggestion, issued another
5
order, directing transmission-owning utilities either to
participate in an RTO or to explain their refusal to do so. See
Regional Transmission Orgs., Order No. 2000, FERC Stats. &
Regs. ¶ 31,089 (1999), 65 Fed. Reg. 810 (2000) (“Order No.
2000”); see also Pub. Util. Dist. No. 1, 272 F.3d at 612. And
while participation was still voluntary (FERC apparently
favored gradual steps in advancing its goals), see id. at 616,
electric utilities took the Commission’s cue and began to form
RTOs and transfer operational control of their transmission
facilities to ISOs.
One such ISO created in the wake of Order Nos. 888 and
2000 was the Midwest ISO (“MISO”), approved by FERC in
1998 to organize as a non-profit, non-stock corporation. See
Midwest Indep. Transmission Sys. Operator, Inc., 84 FERC
¶ 61,231, at 62,138-39 (1998). The utilities that organized the
MISO retained ownership and the physical operation and
maintenance of their own transmission facilities, but the MISO
was responsible for functional control over the transmission
system, which included managing transmission availability and
capacity, requests for transmission service, available ancillary
services, and security. FERC conditionally approved a
transmission tariff that provided a universal rate for all
customers receiving these services from the MISO system. That
tariff would be paid immediately by customers of all new
wholesale and existing unbundled retail transmission service, id.
at 62,167, and even though customers of existing wholesale
services would now receive them through the MISO, they were
afforded the benefit of their rates under existing agreements
(“grandfathered agreements”) and exempted from the MISO
transmission tariff for six years. Id. The question before us is
whether petitioners, who are customers of these grandfathered
agreements and do not yet pay MISO service rates (the
transmission tariff), must nonetheless pay the administrative
6
costs associated with managing the MISO (an administrative
tariff), from which they receive their transmission service.
This is not our first review of a dispute involving MISO
tariffs and parties to agreements grandfathered into the MISO
system. In Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361 (D.C. Cir. 2004), we were asked to determine whether
FERC may require the transmission owners to pay the MISO’s
administrative costs (the same costs at the center of the petition
now before us) for service provided to customers of
grandfathered agreements. Id. at 1367. The transmission owners
argued that FERC violated the principle of “cost causation,”
which we had described as “requir[ing] that all approved rates
reflect to some degree the costs actually caused by the customer
who must pay them.” Id. at 1368 (quoting KN Energy, Inc. v.
FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992)). The transmission
owners argued that the costs imposed upon them for MISO
service offered to customers of grandfathered agreements
outweighed the benefits to those customers who, while receiving
service under the MISO system, did not pay the MISO’s
universal transmission rate for the six-year transition period and
therefore, according to the transmission owners’ argument, did
not “use” the ISO. See id. at 1369. Noting that the
administrative charges in dispute covered “the costs of having
an ISO,” and that “the [Transmission] Owners . . . benefit from
having an ISO,” id. at 1371, this Court concluded that “FERC
correctly determined that they should share the cost of having an
ISO,” id., even for bundled and grandfathered loads that deliver
the same benefits afforded customers who are actually using an
ISO (i.e., receiving electric service under a universal
transmission rate), see id. The transmission owners were thus
responsible for paying the administrative costs (now in dispute
before us) on behalf of all of their customers, including those
customers who do not use (i.e., do not pay the universal
transmission rate for service under) the ISO.
7
Faced with this Court’s decision, and having thus
exhausted their attempts to avoid paying the disputed charges
altogether, the transmission owners proposed to pass the bill on
to their customers by assessing additional charges (under
“Schedule 23”) to collect the MISO administrative costs they
now owed on grandfathered loads. FERC’s order conditionally
accepting the owners’ proposal to collect those costs from
customers is the subject of the petition for review currently
before us.
The transmission owners’ attempt to pass the MISO’s
administrative costs to customers of grandfathered agreements
is not their first. They had previously proposed the imposition of
two sets of administrative charges: Schedule 10 charges, which
recover the costs of running the MISO itself, and Schedule 17
charges, which recover the costs of developing and running the
MISO’s energy markets. But this prior attempt failed when
FERC ruled that the transmission owners had not demonstrated
that the existing rates paid by customers taking service under the
grandfathered agreements did not already include Schedule 10
charges, see Midwest Indep. Transmission Sys. Operator, Inc.,
102 FERC ¶ 61,192, at 61,533-34 (2003); Midwest Indep.
Transmission Sys. Operator, 104 FERC ¶ 61,012, at 61,031
(2003), and Schedule 17 charges, see Midwest Indep.
Transmission Sys. Operator, Inc., 108 FERC ¶ 61,236, at
62,322 (2004). The Commission did note, however, that the
transmission owners could ultimately pass through these costs
as “new services,” id., if they could demonstrate that the
services were indeed “new.”
The transmission owners took the hint. They proposed
charges for new services and FERC, in its March 24, 2005 order
(now under review before us), conditionally allowed the owners
to impose Schedule 23 charges, which recover both Schedule 10
8
and Schedule 17 charges. Transmission Owners of the Midwest
Indep. Transmission Sys. Operator, Inc., 110 FERC ¶ 61,339
(2006) (“Initial Order”). The Commission’s reasoning resembled
our own in Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361 (D.C. Cir. 2004): the Schedule 10 and Schedule 17
charges to be collected under Schedule 23 would recover the
costs associated with benefits (including regional transmission
pricing, regional transmission system planning, and improved
grid reliability and efficiency) provided to all customers
receiving service under the MISO, including customers of
grandfathered agreements. See Initial Order at 62,348-50. In
response to arguments that the benefits identified by the
Commission in its proposal are not enjoyed by customers to
grandfathered agreements because those customers do not use
MISO’s energy markets or because the grandfathered
agreements already provide such benefits, the Commission
concluded that the MISO provides fundamentally new services
and benefits that are different than those provided under the
grandfathered agreements. See id at 62,350.
In response to parties’ assertions that the Commission
had already denied recovery of Schedule 10 and 17 charges from
customers to grandfathered contracts in its previous orders, the
Commission noted that earlier proposals to collect those charges
failed to demonstrate that the grandfathered contracts did not
already include a mechanism for assessing the administrative
charges in dispute. Id. In reviewing the transmission owners’
latest proposal, however, the Commission found that the
deficiencies in earlier proposals had been addressed and
corrected. The transmission owners had, according to FERC,
ultimately demonstrated by argument and evidence what they
had previously failed to demonstrate: the grandfathered
agreements did not, in fact, provide a mechanism for the
recovery of charges associated with the administration of the
MISO, which provided new benefits even to customers receiving
9
service governed by grandfathered agreements. The Commission
further concluded that, because the administration of the MISO
provided new benefits to these customers, the transmission
owners would not run afoul of the Federal Power Act (“FPA”)
by charging their customers an administrative tariff—the
Schedule 10 Cost Adder this Court previously required the
owners to pay on their customers’ behalf.
FERC denied requests to rehear the Initial Order,
reiterating its conclusion that the benefits provided by the MISO
“could not have been provided by the MISO [transmission
owners] to the customers [of grandfathered agreements] prior to
the advent of the MISO,” and, therefore, the costs of providing
those benefits, collected under Schedule 23, “are separate and
distinct from the costs that the [transmission owners] recover
under current provisions [of grandfathered agreements].”
Transmission Owners of the Midwest Indep. Transmission Sys.
Operator, Inc., 113 FERC ¶ 61,122, at 61,476 (2006)
(“Rehearing Order”).
II.
We begin our analysis by addressing a jurisdictional
challenge asserted by intervenors in support of petitioners. They
do not dispute that we have jurisdiction over this matter, but
instead argue that FERC lacked jurisdiction to approve Schedule
23, the proposed tariff, because it assesses the MISO’s costs on
municipal and cooperative entities not subject to FERC’s
jurisdiction. Intervenors’ Br. at 4-17. Petitioners do not raise this
argument. And as we have previously noted, “absent
extraordinary circumstances, intervenors ‘may join only on a
matter that has been brought before the court’ by a petitioner.”
Cal. Dep’t of Water Res. v. FERC, 306 F.3d 1121, 1126 (D.C.
Cir. 2002) (quoting Ala. Mun. Distrib. Group v. FERC, 300 F.3d
877, 879 (D.C. Cir. 2002)). Although we must address
10
intervenors’ claim when the issue they raise was preserved in
their requests for Commission rehearing, see id. at 1126, neither
of these intervenors before us filed a petition for review “within
sixty days after the order of the Commission upon the
application for rehearing,” as required by Section 313(b) of the
FPA, 16 U.S.C. § 825l(b), and thus have failed to satisfy a
statutory requirement to guarantee judicial review of their claim,
see Cal. Dep’t of Water Res., 306 F.3d at 1126-27. We may,
nevertheless, exercise our discretion to consider intervenors’
claims, even absent extraordinary circumstances. Synovus Fin.
Corp. v. Bd. of Governors of Fed. Res. Sys., 952 F.2d 426, 433
(D.C. Cir. 1991) (permitting reviewing court to consider
intervenor’s challenge to agency authority “consistent with this
court’s traditionally flexible approach toward appellate
procedure”). Because we believe that intervenors challenge an
“essential predicate” to the issue on review, see id. at 434
(internal quotation marks and citation omitted), we consider
their jurisdictional argument, but conclude that it is without
merit.
As FERC has argued, see Respondent’s Br. at 35,
Section 201(b) of the FPA, 16 U.S.C. § 824(b), grants FERC
“jurisdiction over all rates, terms and conditions of electric
transmission service provided by public utilities in interstate
commerce, as well as over the sale of electric energy at
wholesale.” Me. Pub. Util. Comm’n v. FERC, 454 F.3d 278, 282
(D.C. Cir. 2006) (citations and internal quotation marks
omitted). Although the FPA exempts certain governmental and
cooperatively-owned entities from FERC regulation, see 16
U.S.C. § 824(f) (as amended by the Energy Policy Act of 2005,
Pub. L. No. 109-58, § 1291(c), 119 Stat. 594, 985 (2005)), that
exemption applies only to the provision of transmission services
by the exempted entity, not to their receipt of services from
regulated entities. See Initial Order at 62,350; Rehearing Order
at 61,480. FERC’s jurisdiction over services provided by the
11
MISO, a public utility providing interstate electric transmission
service, does not depend on the identity of the MISO’s
customers. As our sister circuit has held,
It would be inconsistent with the policy of [the
FPA], as well as with certain of its
provisions . . . to hold that . . . [exempted
entities] are excluded from the benefits of the
regulation of the utilities from which they buy.
The entire thrust of Part II [of the FPA] is toward
the seller at wholesale, not the buyer.
Cal. Elec. Power Co. v. FPC, 199 F.2d 206, 209 (9th Cir.
1952); see also United States v. Pub. Util. Comm’n of Cal., 345
U.S. 295, 314-15 (1953) (noting that Federal Power
Commission’s “long assertion that it has authority over rates of
sales to municipalities has probably risen to the dignity of an
agency policy,” and was entitled to deference). We agree.
Having satisfied ourselves that FERC had jurisdiction to
approve the challenged tariff, we next review FERC’s order
under the familiar arbitrary and capricious standard. See 5
U.S.C. § 706(2)(A); Entergy Servs., Inc. v. FERC, 319 F.3d
536, 541 (D.C. Cir. 2003). We accept the Commission’s factual
findings if they are supported by substantial evidence, see 16
U.S.C. § 825l(b), and affirm its orders where FERC has
“examine[d] the relevant data and articulate[d] a . . . rational
connection between the facts found and the choice made.”
Motor Vehicles Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co.,
463 U.S. 29, 43 (1983) (internal quotation marks and citation
omitted). “[A]n agency must conform to its prior practice and
decisions or explain the reason for its departure from such
precedent,” United Mun. Distrib. Group v. FERC, 732 F.2d 202,
210 (D.C. Cir. 1984) (citation omitted), and must provide
“reasoned analysis indicating that prior policies and standards
12
are being deliberately changed, not casually ignored.” Greater
Boston Int’l Television Corp., 444 F.2d 841, 852 (D.C. Cir.
1970). We are “particularly deferential” when FERC is involved
in the highly technical process of ratemaking. Ass’n. of Oil Pipe
Lines v. FERC, 83 F.3d 1424, 1431 (D.C. Cir. 1996) (citing
Time Warner Entertainment Co. v. FCC, 56 F.3d 151, 163
(D.C. Cir. 1995) (“Because agency ratemaking is far from an
exact science and involves policy determinations in which the
agency is acknowledged to have expertise, our review thereof
is particularly deferential.”)). See also Permian Basin Area Rate
Cases, 390 U.S. 747, 790 (1968) (“[T]he breadth and
complexity of the Commission's responsibilities demand that it
be given every reasonable opportunity to formulate methods of
regulation appropriate for the solution of its intensely practical
difficulties.”).
III.
We are asked in this case to determine whether the
Commission’s decision to approve a disputed tariff meets the
minimum standards for reasoned decisionmaking required by
the Administrative Procedure Act (“APA”). See 5 U.S.C.
§ 706(2)(A). We conclude that it does. As we have already
noted, the MISO’s costs may reasonably be assessed on all
transmission loads delivered under the MISO grid, including
those loads governed by grandfathered agreements, because the
benefits of an ISO flow to all who transact on the grid. See
Midwest ISO Transmission Owners, 373 F.3d at 1368-71. The
question now before us is whether FERC’s approval of the
method proposed to collect these costs from customers was
unreasoned. We need only inquire whether FERC has examined
the relevant data and articulated a rational connection between
the facts found and the choice made. See Motor Vehicles Mfrs.
13
Ass’n, 463 U.S. at 43. We find that it has, especially in light of
the particular deference afforded the Commission’s
determination in this case, see Ass’n of Oil Pipe Lines, 83 F.3d
at 1431.
In the order under review, the Commission scrutinized
and then accepted the transmission owners’ assertion that the
costs of operating the MISO and its energy markets were not
recovered under the grandfathered agreements because the
benefits brought by the MISO represent “new services” not
previously provided under those pre-ISO grandfathered
contracts. This argument—that the benefits that flow from
having an ISO constitute “new services”—is hardly new. FERC
had approved a similar rate hike in another region with another
ISO. See Initial Order at 62,348 (citing Cal. Indep. Sys.
Operator Corp., Opinion No. 463, 103 FERC ¶ 61,114 (2003),
order on reh’g, 106 FERC ¶ 61,032 (2004) (finding that
proposed rate recovered the California ISO’s costs for “new
services,” which included planning and operation of the
transmission grid that was “significantly different” than the
previous system and improved reliability and delivery of
ancillary services, increased efficiency and cost-effectiveness,
and created new market opportunities to customers served under
grandfathered agreements)). The Commission did nothing more
with respect to the MISO transmission owners’s proposal than
it had done to the California ISO transmission owners’ proposal.
It first set out to determine whether the grandfathered
agreements in this case already provide for the MISO benefits
identified by the Commission and by this Court in Midwest ISO
Transmission Owners. Next, the Commission examined whether
the rates under those agreements already recover the costs
associated with such benefits. In so doing, the Commission
reiterated the benefits provided by the MISO to customers
receiving service under grandfathered agreements. Those
14
benefits include (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. See Initial Order at 62,348-49; Rehearing
Order at 61,477-78. On the basis of these findings, the
Commission concluded that
The services associated with . . . [S]chedules 10
and 17, as a whole, represent a monumental
transformation with respect to the way that
electricity is sold and distributed in the Midwest
ISO region—a change that will bring substantial
[new] benefits to all those transacting over the
Midwest ISO grid, including . . . customers [of
grandfathered agreements]. These services . . .
could not have been provided by the Midwest
ISO [transmission owners] to the . . . customers
[of grandfathered agreements] prior to the advent
of the Midwest ISO, and the costs that the
Midwest ISO [transmission owners] propose to
pass through to the customers [of grandfathered
agreements] under [S]chedule 23 thus are
separate and distinct from the costs that the
Midwest ISO [transmission owners] recover
under current provisions [of the grandfathered
agreements].
Initial Order at 62,350 (emphasis added).
FERC reasonably rested its decision on this “new
services” analysis and considered evidence that the costs to be
15
collected under Schedule 23 are “separate and distinct from the
costs collected under the grandfathered agreements.” Initial
Filing of the Midwest ISO Transmission Owners (Jan. 13,
2005), Exhibit No. MISO TOs-1 (Testimony of Alan C. Heintz)
at 9-10 (“Heintz Testimony”) (describing benefits and services
provided by Midwest ISO that were not available when
grandfathered agreements were entered into).
Petitioners next argue that FERC’s approval of Schedule
23 costs imposed on customers of grandfathered agreements
constitutes an irrational departure from Commission policy and
precedent, which requires that grandfathered agreements be
honored without interference. See Petitioner’s Br. at 28. Citing
FERC Orders No. 888 and 2000, see id. at 29, Petitioners assert
that FERC has consistently (1) “held that grandfathered
contracts should be honored,” id. and (2) refused to interfere
with those contracts by allowing their inclusion of Schedule 10
and Schedule 17 costs. See id. (citing Midwest Indep.
Transmission Sys. Operator, Inc., Opinion No. 453-A, 98 FERC
¶ 61,141 (2002) (order on rehearing) and Midwest Indep.
Transmission Sys. Operator, Inc., 108 FERC ¶ 61,236, at 62322
(2004), respectively). Petitioners conclude that FERC’s order,
which permits the inclusion of Schedule 10 and Schedule 17
costs through the addition of Schedule 23 to grandfathered
agreements, must therefore be vacated absent FERC’s rational
explanation for inconsistencies with its own precedent. See
Petitioner’s Br. at 30. Intervenors offer a similar argument by
alleging that the Commission violated principles of res judicata
and collateral estoppel when it ignored its prior orders denying
the recovery of the MISO’s costs from customers of
grandfathered agreements. See Intervenor’s Br. at 17-21.
The Commission, in response, argues that its orders were
consistent with its prior rulings on the pass-through of the
16
MISO’s costs to customers of grandfathered agreements and did
not violate any relevant preclusion doctrines. FERC contends
that it could not previously make a definitive cost recovery
decision because the transmission owners had failed to provide
sufficient evidence that they would be unable to recover
Schedule 10 charges as a result of the Commission’s rulings. See
Midwest Indep. Transmission Sys. Operator, 102
FERC ¶ 61,192, at 61,533-34. FERC offered the same
reasoning to justify its denial of a proposed pass-through for
Schedule 17 charges (created to cover the cost of running ISO
energy markets)—the owners had failed to make a sufficient
showing. See Midwest Indep. Transmission Sys. Operator, 108
FERC ¶ 61,236, at 62,322 (specifically noting that the owners
had failed to provide any information regarding whether the
grandfathered agreements already provided for the recovery of
Schedule 17 charges). In the order under review, the
Commission accepted a new tariff provision (Schedule 23) that,
FERC argues, recovers Schedule 10 and 17 charges not already
recovered under the grandfathered agreements. The Commission
justifies its acceptance of Schedule 23 by describing evidence
that its charges were associated with new services not previously
provided under the agreements. See Initial Filing of Midwest
ISO Transmission Owners (Jan. 13, 2005), Heintz Testimony;
see also Initial Order at 62,349-50. We agree that the
Commission’s decision not to approve a proposed tariff under
review due to insufficient evidence does not bar FERC from
approving a similar tariff once sufficient evidence is proffered.
In further support of FERC’s reasoned decisionmaking,
and in response to this Court’s order, intervenors on behalf of
the Commission have submitted documents on file with FERC
describing the “new services” for which Schedule 23 charges
were proposed and approved. These tariff sheets and agreement
sheets indicate, among other things, the construction of new
17
facilities to enhance regional competition, Tariff Sheet 1833-52,
as well as facilities that enhance regional transmission
reliability, id.; see also Agreement Sheets 61 & 159. These
record documents also describe regional services such as the
calculation of available transmission capability, evaluation of
transmission requests, and resolution of transmission constraints.
See, e.g., Agreement Sheets 103-4a. We agree with intervenors
that these documents likewise support their argument (and
FERC’s conclusion) that Schedule 23 charges were assessed for
“new services,” and therefore conclude that the Commission’s
decision was rational and based on substantial record evidence.
Finally, petitioners argue that our review of this case
must conform to the doctrine articulated in the Supreme Court’s
decisions United Gas Pipe Line Co. v. Mobile Gas Serv. Corp.,
350 U.S. 332 (1956), and FPC v. Sierra Pacific Power Co., 350
U.S. 348 (1956). 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 FPA.
Me. Pub. Util. Comm’n v. FERC, 454 F.3d at 283(citation
omitted). Under such contracts, utility providers are prohibited
from filing a new rate for services currently provided (and
therefore subject to) the negotiated contract rate. Id. FERC is
similarly prohibited from modifying the contract rate under the
authority otherwise granted by Section 206 of the FPA, except
where the modification is both required by the “public interest”1
1
The Supreme Court has described the public interest standard
as requiring modification of previously approved contracts in
instances “where [the existing rate structure] might impair the
financial ability of the public utility to continue its service, cast upon
other consumers an excessive burden, or be unduly discriminatory.”
Sierra Pac. Power Co., 350 U.S. at 355.
18
and upon a showing that the changes are just, reasonable, and
nondiscriminatory. Id. (citations omitted). We view the “public
interest” standard as “much more restrictive than the FPA’s ‘just
and reasonable’ standard.” Potomac Elec. Power Co. v. FERC,
210 F.3d 403, 407 (D.C. Cir. 2000); see also Papago Tribal
Auth. v. FERC, 723 F.2d 950, 954 (D.C. Cir. 1983) (describing
public interest standard as “practically insurmountable”). As
discussed above, FERC has concluded that Schedule 23 imposes
a new rate to recover the costs of new benefits and services
received from the Midwest ISO and its energy markets by
customers to grandfathered agreements. See Initial Order at
62,349-50; Rehearing Order at 61,477. The disputed Schedule
23 tariff does not “modify the rates, terms or conditions of
services provided under the [grandfathered agreements],”
Rehearing Order at 61,476. The Mobile-Sierra doctrine,
powerful though it may be where it applies, is not implicated in
this case and petitioners can therefore find no refuge in its
protection.
IV.
For the foregoing reasons, we conclude that FERC’s
order comports with reasoned decisionmaking, and we deny the
petition for review.
So ordered.