Ameren Services Co. v. Federal Energy Regulatory Commission

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued September 22, 2017 Decided January 26, 2018

No. 16-1075

AMEREN SERVICES COMPANY, ET AL.,
PETITIONERS

v.

FEDERAL ENERGY REGULATORY COMMISSION,
RESPONDENT

AMERICAN WIND ENERGY ASSOCIATION, ET AL.,
INTERVENORS

Consolidated with 16-1304, 16-1373

On Petitions for Review of Orders of
the Federal Energy Regulatory Commission

Christopher R. Jones argued the cause for petitioners.
With him on the briefs was Kurt H. Jacobs.

Holly E. Cafer, Senior Attorney, Federal Energy Regulatory
Commission, argued the cause for respondent. With her on the
brief were David L. Morenoff, General Counsel, and Robert H.
Solomon, Solicitor.
 2

Bruce A. Grabow, Jennifer Brough, and Gene Grace were
on the joint brief for intervenors American Wind Energy
Association, et al. in support of respondent.

Before: ROGERS and TATEL, Circuit Judges, and
SILBERMAN, Senior Circuit Judge.

Opinion for the Court filed by Senior Circuit Judge
SILBERMAN.

Dissenting opinion filed by Circuit Judge ROGERS.

SILBERMAN, Senior Circuit Judge: When new sources of
power generation connect to the existing transmission grid, the
grid often requires new construction beyond the point of
interconnection in order to accommodate the increased flows of
electricity. FERC issued a series of orders empowering
incoming generators within the Midcontinent Independent
System Operator (MISO) region1 to elect to self-fund this new
construction, or to seek financing from third parties, regardless
of whether the current grid owners wish to fund the construction
themselves.

The Commission justified the orders on two grounds. First,
it found that allowing transmission owners to choose between
funding options – and thus, potentially, to impose subsequent
charges to generators via transmission owner funding – could
allow the transmission owners to discriminate among generators.
Secondly, it held that the charges to generators would be (or

1
MISO operates in fifteen states located largely within the
midwestern United States, along with the Canadian province of
Manitoba.
 3

could be) unjust and unreasonable under the Federal Power Act.
Petitioning transmission owners challenge both grounds. We
conclude that Petitioners are correct regarding the
discrimination point: there is neither evidence nor economic
logic supporting FERC’s discriminatory theory as applied to
transmission owners without affiliated generation assets.

FERC’s second ground raises a unique and important
conceptual issue. Petitioners argue that involuntary generator
funding compels them to construct, own, and operate facilities
without compensatory network upgrade charges – thus forcing
them to accept additional risk without corresponding return as
essentially non-profit managers of these upgrade facilities. We
do not think that FERC adequately responded to this argument.
We therefore remand the case to the Commission.

I.

We have previously explained the series of steps FERC
took to unbundle the electric power system, enabling and
encouraging new independent generators to create a competitive
market for power generation.2 Transmission owners, which had
previously served their own vertically integrated sources of
power generation, were obliged to accept power from any source
on a non-discriminatory basis.

2
For a detailed description of the series of FERC orders that led
to the development of competitive power generation markets and the
creation of MISO, see Wisconsin Public Power, Inc. v. FERC, 493
F.3d 239, 246-50 (D.C. Cir. 2007); Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1363-65 (D.C. Cir. 2004).
 4

For independent generators to utilize the grid, they must
first connect to it. FERC thus used its rulemaking powers to
issue Order No. 2003, which standardized the procedures for
generator interconnection and directed each transmission
network to maintain a pro forma generator interconnection
agreement.3 Order No. 2003 also established the “at or beyond”
rule, which distinguished between two types of new construction
necessary to connect new generation sources into the grid. See
Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d
1277, 1284-86 (D.C. Cir. 2007). The first category, called
“interconnection facilities,” includes those facilities and
equipment that lie between the generation source and the point
of interconnection with the transmission network. Under the “at
or beyond” rule, the cost of interconnection facilities are the sole
responsibility of the incoming generator. That allocation of
costs is undisputed in this proceeding. And Petitioners do not
own or manage those “interconnection facilities.” The second
category includes those additional facilities and equipment that
are needed beyond the “point of interconnection” – in other
words, any new construction that occurs within Petitioners’
transmission grid itself to accommodate the incoming flows of
new power. This latter category of construction, called
“network upgrades,” is the focus of the present dispute.

* * *

3
Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003),
order on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160,
order on reh’g, Order No. 2003-B, FERC Stats. & Regs. 31,171
(2004), order on reh’g, Order No. 2003-C, FERC Stats. & Regs. ¶
31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util.
Comm’rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
 5

As we have also explained, FERC encouraged the creation
of Regional Transmission Organizations (RTOs) to integrate the
fragmented transmission grid on a regional basis, along with
Independent System Operators (ISOs) as non-profit entities
which would control access to the grid within their respective
regions. Wisconsin Public Power, Inc., 493 F.3d at 247. In
Order No. 2003, the Commission set a default rule that
transmission owners would bear responsibility for the network
upgrades, but gave ISOs “flexibility to customize its
interconnection procedures and agreements to meet regional
needs.” Order No. 2003 at P 827; id. at P 676. In this case, we
encounter MISO, which qualifies as both an RTO and an ISO.

Originally, MISO had allocated the costs equally between
the incoming generator and the transmission owner. As such,
under transmission owner funding – which it could choose – the
transmission owner would initially provide the capital for
construction, but would recover 50 percent of that capital (a
“return of” capital), along with an appropriate return on that
capital, through network upgrade charges. It would fund the
other 50 percent of the costs by passing them on to all of its
customers through its rates – again, including an appropriate rate
of return. Under generator funding, the generator would initially
provide the capital for construction, and would receive 50
percent of that capital from the transmission owner through
credits for transmission service. E.ON at P 3.

But a problem arose: this 50/50 arrangement placed most
of the cost burden on the pricing zone where interconnection
occurred, but the power from the new generation sources often
exceeded the load within those local zones in which they
connected. Midwest Independent Transmission System
 6

Operator, Inc., 129 FERC ¶ 61,060, at P 7 (2009) (“MISO Tariff
Amendment”). As a result, the local customers of the
transmission owner bore a disproportionate share of the cost
burden of upgrades that supported power that would ultimately
benefit more remote customers throughout the MISO region. Id.
at P 11. Rather than forcing their local customers to shoulder
this regional burden, several local transmission owners
threatened to withdraw from MISO if the cost allocation
remained unchanged. Id. at P 10.

To remedy this problem, MISO proposed (and FERC
approved) a new allocation of capital costs: for network
upgrades rated at 345 kilovolts or above, the interconnecting
generator bears 90 percent of those costs, and transmission
owners (and their local customers) bear 10 percent. In other
words, the 10 percent would be included in the transmission
owner’s rate base. For projects rated below 345 kilovolts, the
interconnecting generator bears 100 percent of the costs. This
reallocation was intended to comport with FERC’s “principle
that network upgrades should be paid for by the parties that
cause and benefit from such upgrades.” MISO Tariff
Amendment at P 3.

The manner in which the incoming generator and
transmission owner actually pay these capital costs depends
upon the way the network upgrades are funded. Originally, the
MISO tariff contained three options for providing the capital
required to construct the network upgrades. We need not
discuss the first because it was removed by the Commission in
its E.ON decision.4

4
E.ON Climate & Renewables North America, LLC v. Midwest
Indep. Transmission Sys. Op., Inc., 137 FERC ¶ 61,076 (Oct. 20,
 7

Under the second alternative, Option 2 or “generator
funding,” the interconnecting generator would provide the
funding for the network upgrades prior to construction. The
transmission owner would not refund this capital to the
interconnecting generator, and would neither include the capital
in its rate base nor charge the interconnecting generator a return
on that capital.5 In short, generator funding means the owner of
the transmission grid neither pays for, nor earns a return upon,
the new construction that takes place within its network.

Under the third alternative, “transmission owner funding,”
the transmission owner pays for the construction of the upgrades
to its network and then recovers the incoming generator’s
portion of the cost burden over time through periodic network
upgrade charges that include a return on the capital investment.
These network upgrade charges are paid from the incoming
generator to the transmission owner over the duration of the
agreement. Importantly, they include both a return of capital,
which is the 90 percent cost reimbursement paid over time as the
network upgrades depreciate, and a return on capital. They are
thus economically equivalent to inclusion in the rate base, with
the exception that they are charged specifically to the incoming
generator rather than to all of the transmission owner’s
customers. Any portion of the upgrade costs that remains to be

2011).
5
Under generator funding, the transmission owner does provide
a refund of the reimbursable portion of construction costs – which
amount to ten percent of capital costs for projects rated at 345
kilovolts or higher – in the form of a credit toward transmission
services charged to the interconnecting generator. The generator
receives no reimbursement for the remaining ninety percent of these
larger projects.
 8

borne by the transmission owner is then passed on to all of its
customers through its rates.

Following the Commission’s E.ON decision, then, it was
clear that the transmission owner could choose between two
options – generator funding or transmission owner funding – to
finance construction of network upgrades when an incoming
generator sought to directly interconnect with its network.

To further complicate the matter, however, the addition of
new generation sources can cause second-order effects across
the grid. Sometimes, in order to support flows of power from a
new source, network upgrades must be made by transmission
owners that do not connect directly to the incoming generator.
And in other instances, the coincidence of multiple
interconnection requests can create a need for a set of common
network upgrades, which enable the grid to support the several
incoming generators. In these two situations, MISO’s tariff did
not initially permit transmission owners to choose between
funding options.

It was that disparity between the treatment of direct and
indirect network upgrades which gave rise to this case. In 2014,
when faced with the prospect of building network upgrades to
support an indirectly connected incoming generator, a
transmission owner named Otter Tail requested that MISO offer
it the same choice (between generator funding and transmission
owner funding) enjoyed by directly connected transmission
owners. MISO consented, and submitted an agreement to FERC
that would allow Otter Tail to elect transmission owner
 9

funding.6 The incoming generator objected to this request,
preferring instead to utilize generator funding for the network
upgrades that would be needed to support its power.

Otter Tail also filed a complaint under Sections 206 and 306
of the Federal Power Act. It contended that the disparity
between directly connected transmission owners (who could
choose to fund the upgrades to their networks) and indirectly
connected transmission owners (who could not choose
transmission owner funding) rendered MISO’s tariff unjust and
unreasonable. Otter Tail requested that FERC order MISO to
bring all transmission owners into alignment by modifying its
tariff to allow the choice of transmission owner funding for
indirect interconnections.

The Commission agreed with Otter Tail that this disparity
was unsupportable. In its June 2015 Order,7 the first of the
orders under review in this case, it found that because “the
funding and construction obligations are equal whether the
connection of a new generator is direct or indirect . . . the same
funding options should be available to all interconnection
customers in MISO.” June 2015 Order at P 47. Ironically, it
cured the disparity not by providing the choice of transmission
owner funding to indirectly connected owners – but instead by
removing that choice from those with direct connections. Otter
Tail was hoist on its own petard.

6
This unexecuted FCA was submitted pursuant to Section 205 of
the Federal Power Act, 16 U.S.C. § 824d (2012).
7
Midwest Indep. Sys. Operator, Inc., 141 FERC ¶ 61,220 (Jun.
18, 2015) (“June 2015 Order”).
 10

The Commission determined that providing directly
connected transmission owners with the ability to select
transmission owner funding “may be unjust, unreasonable,
unduly discriminatory or preferential because it . . . may result
in discriminatory treatment by the transmission owner of
different interconnection customers.”8 June 2015 Order at P 48
(emphasis added). This discriminatory treatment, according to
FERC, stemmed from the difference in costs borne by the
generator under the two types of funding.

* * *

Those cost differences, according to the Commission, had
two main causes. FERC thought that generators missed the
opportunity to seek favorable construction funding in
competitive capital markets; in other words, the use of
transmission owner funding could prevent the generator from
finding a better deal from a third party. June 2015 Order at P
48. Second, FERC contended that transmission owner funding
imposed a more onerous “security” requirement on generators.
June 2015 Order at P 49 & n.110. Transmission owners
required generators to provide some form of financial assurance

8
This language suggests that FERC thought transmission owner
funding was unjust and unreasonable only because it was
discriminatory. However, in the final orders the Commission seems
to rest on two separate grounds: potential discrimination by
transmission owners among generators, and excessive costs charged
to generators with no increase in service, which FERC found to be
unjust and unreasonable. See Otter Tail Power Co. v. Midcontinent
Indep. Sys. Operator, Inc., 153 FERC ¶ 61,352 at P 29, 32, 33 (Dec.
29, 2015) (“December 2015 Order”); Otter Tail Power Co. v.
Midcontinent Indep. Sys. Operator, Inc., 156 FERC ¶ 61,099 at P 15,
19 (Aug. 9, 2016) (“August 2016 Order Denying Rehearing”).
 11

– such as a guarantee, surety bond, or letter of credit – that was
sufficient to cover the cost commitments undertaken by the
transmission owner in constructing the network upgrades.
Under generator funding, this requirement lasted only for the
duration of construction. But under transmission owner funding,
security was required for the duration of the funding agreement.
As an example, one proposed transmission owner funding
agreement specified that an incoming generator would maintain
a letter of credit over a term of 20 years. December 2015 Order
at P 33 & n.60.

Given these tentative findings, FERC instituted a formal
adjudicatory proceeding under Section 206 of the Federal Power
Act, requiring MISO to either modify its tariff to require
generator consent for transmission owner funding, or to explain
why the Commission’s views were not correct. This proceeding
attracted a large cohort of intervenors; various transmission
owners (including Petitioners), independent generators, and
associations that represent those groups each contributed
comments before the Commission. In the second of the orders
under review in this case (“December 2015 Order”), FERC
affirmed its earlier finding that “it is potentially unjust,
unreasonable and unduly discriminatory to deprive the
interconnection customer of the ability to provide its own capital
funding.” This petition for review followed.9

9
In the third and fourth of the orders under review, FERC rejected
another petition from six transmission owners (“August 2016 Order
Denying Rehearing”) and accepted MISO’s compliance filing to
remove a transmission owner’s ability to choose between funding
options from the MISO Tariff (“August 2016 Order on Compliance”).
In the fifth and final order on review in this case (“October 2016
Order”), the Commission denied a procedurally-oriented request for
 12

II.

The Commission’s position before us largely tracks its final
decision below. It relied, as we noted, on two grounds to
determine that transmission owners may not insist on
transmission owner funding, but that generators must instead
have the option to self-fund. The first is that giving transmission
owners the option to fund the upgrades provides them with the
power to discriminate amongst generators who wish to connect
to the grid. (Discrimination is, of course, prohibited by the
Federal Power Act. See 16 U.S.C. §§ 824d(b); 824e(a).)
Petitioners argue vigorously, however, that there is neither
evidence of discrimination10 nor any economic incentive on the
part of transmission owners to discriminate. To be sure, if the
transmission owners still owned integrated generation facilities,
that would present a competitive motive. But in emphasizing
Order No. 888 and the Supreme Court’s decision in New York v.
FERC, 535 U.S. 1 (2002), the dissent harks back to a time we
once described as “the bad old days,” when transmission
companies also owned generation facilities and operated as
vertically integrated monopolies. Midwest ISO Transmission
Owners v. FERC, 373 F.3d 1361, 1363 (2004); cf. Dissent at 10-
11. This is fighting a battle that has already been won. Here,
only one of the petitioning transmission owners – in Missouri –
still owns a generator; none of the rest do. And FERC did not

rehearing, with reference to its December 2015 Order and August
2016 Orders.
10
The only study alleging evidence of disparate costs charged
generators was conceded by FERC to be flawed. See December 2015
Order at P 33.
 13

pay any attention to that small exception among Petitioners; it
did not limit its order to that generator. Moreover, as we know
from our other cases, the broader trend following Orders No.
888 and 2000 has been toward divestiture by transmission
owners of generation assets.11 Granted, FERC is not obliged to
show actual evidence to support a determination of potential
discrimination, but in the absence of evidence, the Commission
must at least rest on economic theory and logic. We agree with
Petitioners; that is lacking here.

Our dissenting colleague suggests that we actually lack
jurisdiction to consider Petitioners' anti-discrimination argument
– at least insofar as Petitioners point out that only a transmission
owner which also owns a generator would have an incentive to
discriminate – because Petitioners did not explicitly make that
specific point to the Commission. But when Petitioners
vigorously contended there was no evidence to support a finding
of discrimination and no reason to “predict[]” it would occur as
“a foregone conclusion,” Request for Rehearing of the Indicated
Transmission Owners, Docket Nos. EL15-68, EL15-36 (FERC
January 28, 2016) at 23 n.59, it can hardly be thought a new
argument to suggest what might constitute evidence of potential
discrimination, if it were to exist.

11
See, e.g., Calpine Corp. v. FERC, 702 F.3d 41, 43 (D.C. Cir.
2012) (“Order 888 was successful in causing major utilities
nationwide to divest most of their generating facilities . . . .”). See
also generally Wisconsin Public Power, Inc. v. FERC, 493 F.3d 239,
246-50 (D.C. Cir. 2007) (describing the series of Commission orders
that led to the development of MISO and encouraged divestiture of
generation assets).
 14

The second theory upon which FERC based its orders was
that allowing transmission owners to insist on transmission
owner funding would be “unjust and unreasonable” under the
Federal Power Act because it imposed increased costs without
any corresponding increase in service. We should note at the
outset that the Commission does not assert that transmission
owner funding is inherently unjust and unreasonable; it is only
if the transmission owner chooses that method of funding that
FERC believes it crosses the unjust and unreasonable line.
(That suggests that FERC is really seeking to enhance the
generator’s bargaining position vis-a-vis the transmission
owners – which, of course, is why generators have intervened in
support of the Commission.) As we explained, FERC wants
generators to have the option to seek the funding for the new
construction from parties other than the transmission owners
because it asserts that cheaper funding may be available
elsewhere. FERC observes that the transmission owners have
an incentive to increase costs because such costs will either be
included in the rate base – upon which revenue can be
predicated – or in charges back to the generator owner, which
also include a measure of profit. FERC also states that the
transmission owners have no right to the generator’s financing
business.

The Commission contends moreover that generator funding
avoids the larger security costs under transmission owner
funding. We are puzzled by FERC’s reasoning on this point,
because if the generator had found another source of capital to
cover the costs of the upgrade, we can’t imagine that the
generator wouldn’t have to provide the same kind of security to
that third party – covering the risk of default – that it does for
 15

transmission owners.12 Still, it is certainly possible, if not
probable, that a generator could find an alternative source of
capital (including any necessary security) that would be cheaper
than that provided by the transmission owner. Indeed, as the
dissent notes, the Commission states a simple economic truth in
recognizing that the generators "have an incentive to find lowest
cost funding solutions, while transmission owners do not."
Dissent at 6.

But this proposition applies equally to all cost components
of Network Upgrade construction, which Petitioners perform on
the generators' behalf – not merely its funding. By the same
logic, since they bear a greater share of cost responsibility, the
generators also have a sharper incentive than Petitioners to
reduce the costs of raw materials, or construction labor, or
design fees. This is why the generators can challenge inclusion
of any such costs that deviate unreasonably from a fair market
price before the Commission.

In any event, it does not necessarily follow from any
incentive differences that FERC may compel transmission
owners to operate the upgrades without an opportunity to earn
a return. Such a determination would require reasoned
justification by the Commission, and consideration of any
appropriately raised concerns by the parties. And Petitioners do

12
As such, of the two alleged sources of increased costs under
transmission owner funding – a missed opportunity to seek alternative,
cheaper funding and a more onerous security requirement – the second
seems to collapse into the first: any alternative financing package must
account for the risk of loss, whether through an explicit security
requirement (such as a letter of credit) or an implicit willingness to
bear that risk expressed through a higher financing rate.
 16

in fact raise two rather powerful arguments against FERC's
"unjust and unreasonable" theory.

First, they claim that under compelled generator funding,
transmission owners will be forced to assume certain costs that
are never compensated. Keeping in mind that the transmission
owners will own and operate the grid, including the upgrades,
they will bear liability for insurance deductibles and all sorts of
litigation, including environmental and reliability claims (such
as blackout risks). The Commission’s response dismisses these
risks; it asserts that upgrades might actually reduce congestion
risks, see August 2016 Order Denying Rehearing at P 17, but it
makes no real attempt to holistically assess all of the various
risks and benefits to the transmission owner caused by the
addition of the upgrade facilities.

Instead, FERC asserts that because “this case concerns only
the capital costs of facility construction,” Resp.Br. 35, and since
“[t]ransmission owners will recover their cost of service (beyond
capital costs) through their transmission rates,” id. (quoting
December 2015 Rehearing Order P 57), the petitioning
transmission owners have no justifiable complaint.13 But in this
adjudication, FERC never acknowledged that these separate
risks and consequent expenses even exist – they are thought to
be somehow “baked in” to the existing compensation structure.
See August 2016 Order Denying Rehearing at P 13. If
Petitioners are correct that they face increased risk without

13
This recovery is alleged to occur through a process by which
transmission owners recoup their recognized expenses for such line
items as operations and maintenance. See December 2015 Order at P
57 & n. 118.
 17

compensation, that would be relevant and could certainly
undermine FERC’s conclusion.

Contrary to the dissent’s characterization, FERC’s musing
that network upgrades might actually reduce reliability risk is
hardly a “finding” of fact to which we are obliged to defer. It is,
at most, a possibility to be explored – and one that sounds a bit
far fetched to us. In any event, FERC makes no assertion that
any such reduction of reliability risk would be of sufficient
magnitude that the added facilities would actually reduce the net
overall risk borne by the owner-operator. Further, the dissent’s
suggestion that the environmental risks are identical regardless
of who provides capital for the upgrades is something of a
diversion. Of course that is true. The problem is that the risk is
always borne by the transmission owner, and under Option 2,
Petitioners contend they are not compensated for bearing it.
And whether the transmission owner chooses, at its own
expense, to insure that risk is obviously irrelevant. Cf. Dissent
at 14.

We therefore think that FERC inadequately considered
Petitioners’ argument14 that all costs, and risks, are not baked in

14
The dissent contends that Petitioners offered “only bare
generalities about its uncompensated costs, but no specifics.” Dissent
at 13. But risks – which are contingent possibilities of future adverse
events – must be described in hypothetical terms. And Petitioners did
offer specific examples to support the general argument that when
they are denied the opportunity to fund construction that occurs within
their grid, “the return earned is disproportionate to the size,
complexity, and risks of the system the transmission owner owns and
operates.” Request for Rehearing of the Indicated Transmission
Owners, Docket Nos. EL15-68, EL15-36 (FERC January 28, 2016) at
14. Indeed, they cited FERC’s own summary of these risks, noting
 18

– that, in fact, shareholders are forced to accept incremental
exposure to loss with no corresponding benefit. Without
analysis, the Commission casts doubt on the likelihood that
these risks exist. But if Petitioners are conceptually correct that
they bear these risks as owners of the transmission lines, it
supports their basic contention that they are entitled to be
compensated now as owners for operating the upgrades. And
since this contention was raised appropriately, failure to
meaningfully respond to it makes FERC’s decision arbitrary and
capricious. See PSEG Energy Res. & Trade LLC v. FERC, 665
F.3d 203, 208, 209-10 (D.C. Cir. 2011).

Petitioners’ second – and more fundamental – argument is
that FERC’s orders require them to act, at least in part, as a non-
profit business. Put another way, by modifying the transmission
owners’ entire enterprise, FERC’s orders attack their very
business model and thereby create a risk that new capital
investment will be deterred. In its orders, FERC distorted and
dismissed this argument, stating derisively that because
generators bear responsibility for most of the capital costs under
generator funding, the entire enterprise argument “implies that
the affected system operator is owed the interconnection
customer’s financing business.” June 2015 Order at P 50.

that FERC had addressed only one small subset (construction risks
covered by financial security). Id. at 20-22. They offered compliance
with Reliability Standards as just “one example of such risk” that had
not been addressed. Id. at 22. And their subsequent discussion before
us of uncompensated penalties stemming from electrocutions and
blackouts caused by untrimmed trees demonstrates the eminent
sensibility of recognizing “the fundamental reality that all new
facilities bring incremental risk of operation.” Reply Br. 22; see id. at
17-24; Oral Arg. at 5:07-6:20.
 19

FERC seems to believe that transmission owners are simply not
entitled to participate in funding the network upgrades, and
importantly to earn a return on capital.

But a careful reading of Supreme Court precedent reveals
that a regulated industry is entitled to a return that is sufficient
to ensure that new capital can be attracted. See Hope, 320 U.S.
at 603. Therefore, as we have often said, a utility’s return must
allow it to compete for funding in the financial markets. See,
e.g., Maine v. FERC, 854 F.3d 10, 20 (D.C. Cir. 2017).
Investors, however, invest in entire enterprises, not just portions
thereof. FERC must explain how investors could be expected to
underwrite the prospect of potentially large non-profit
appendages with no compensatory incremental return. It is
certainly true, as the transmission owners note, that the answer
FERC offered – to cajole consent from the generators15 – is a
non sequitur.

Our dissenting colleague responds to Petitioners’ primary
argument – that FERC’s order requires them to operate partly as
a non-profit business – by asserting that Hope does not
guarantee that each portion of a regulated business will be
profitable. Dissent at 15. That is, of course, true, but it seems

15
See, e.g., December 2015 Order at P 59 ("Our decision does not
preclude the transmission owner from earning a return on these
network upgrades from the interconnection customer where the
transmission owner and the interconnection customer mutually agree
. . . any return that was available to a transmission owner when the
initial funding election was made on a unilateral basis by the
transmission owner is still available when the transmission owner's
initial funding option is made on a mutually agreed upon basis.").
 20

undisputable that when portions of a business are unprofitable,
it detracts from the attractiveness to investors of the business as
a whole – and that is a concern that the Commission must at
least address under Hope’s capital-attraction standard.

This is to say nothing of the fact that added complexity can
be expected to impose its own form of deterrence upon
investors, via information costs. Even if FERC could somehow
provide protection for each of the many risks involved, potential
investors would need to expend costly time and resources to
examine and understand what the petitioning transmission
owners would call the "non-profit" segments of their business,
in order to verify that they are, in fact, riskless. And investors'
confidence in their own assessment of such risklessness would
itself carry some perceived risk. To the extent that other
comparable utilities do not carry responsibility for such
"non-profit" lines of business, and earn the same rate of return
on the assets in their rate base, they would thus become
relatively more attractive to investment professionals.

Notwithstanding these concerns, the non-profit innovation
might remain bearable so long as the generator-funded upgrades
growing inside the grid remain tiny relative to their host. But if
more and more of a transmission owner’s business is to be
owned and operated on a non-profit basis, these additions would
likely deter investors and diminish the ability of the transmission
grid to attract capital for future maintenance and expansion.
That FERC’s orders cross a rather significant conceptual line
was revealed when FERC’s counsel was asked whether, if a
group of generators got together to fund a billion-dollar upgrade
that totally refurbished a portion of the grid, the transmission
owner would be obliged to operate and assume liability for the
upgrade – with operations and maintenance costs reimbursed,
 21

but no return. The answer, alarmingly, was yes. Oral Arg. at
39:36; see also id. at 51:39-52:15. Transmission owners’ desire
to retain the choice to fund the upgrades is therefore much more
than a claim of entitlement to the generator’s “financing
business.” It is, at root, a desire to retain control over their own
business.

In its discussion of the balance of investor and consumer
interests mandated by Hope, the Commission stresses that
capital costs are ultimately borne by the generator under either
option. But this backward-looking perspective elides Hope’s
forward-looking capital attraction standard. 320 U.S. at 605.
The ex ante question of cost allocation is thus analytically
distinct from the ex post question of responsibility for ownership
and operation that we discussed above. FERC cannot
sufficiently respond to the transmission owners’ clearly stated
concerns about the latter question by merely pointing to the
outcome of the former.

In sum, petitioning transmission owners raise serious
statutory and constitutional concerns with respect to the effect
of compulsory generator-funded upgrades on their business
model. They ask why their current investors should be forced
to accept risk-bearing additions to their network with zero
return. We think an even greater concern is whether any future
providers of capital would choose to enter into that questionable
bargain. See Hope, 320 U.S. at 603. At present, however, we
have no need to reach the merits of those questions. Because the
Commission failed even to respond to these concerns, and
because it offered neither evidence of nor motive for
discrimination by non-vertically integrated transmission owners
among their customers, it is sufficient now to require that it do
so. On remand, FERC should provide reasoned consideration of
 22

these arguments by explaining whether all risks are truly “baked
in,” responding to the transmission owners’ “entire enterprise”
argument, and addressing the effect of these orders on the ability
of transmission businesses to attract future capital.

III.

Setting aside the merits of the case, FERC contends in the
alternative that our review is premature because the transmission
owners can seek to adjust their rates in a future hearing under
Section 205 of the Federal Power Act. We are thus urged not to
intervene on the transmission owners’ behalf, because they can,
and should, simply seek relief from FERC directly in a later
hearing.

But for two reasons, a Section 205 hearing cannot provide
the relief that the petitioning transmission owners seek. First,
FERC’s precedents do not provide compensation for several of
the classes of risks that Petitioners allege will accompany
construction and operation of the network upgrade facilities.
For example, fines and penalties for violations of mandatory
reliability standards and environmental regulations are generally
charged directly to the utility, not passed through to customers
via rate increases. See, e.g., In re SCANA Corp., 118 FERC ¶
61,028 at P 1, 7-8. Further, FERC has stated that it takes a
comprehensive view of a company, its employees, and its
operations when wielding its enforcement power against the
utilities it governs. See generally Enforcement of Statutes,
Orders, Rules, and Regulations, 113 FERC ¶ 61,068 (2005). As
such, compensation for the types of risks identified by the
petitioning transmission owners may not be possible, even if
proven in a future hearing.
 23

The second reason why a Section 205 hearing would be of
little use to the petitioning transmission owners is that FERC has
spoken with utter and consistent clarity as to the question of
whether a rate of return is justified under the generator funding
option. See Resp.Br. 33; August 2016 Rehearing Order PP 12-
20; December 2015 Rehearing Order PP 56-59. If, in a future
Section 205 hearing, the transmission owners were to seek to
include generator-funded assets in their rate base, a negative
result is a foregone conclusion. The relevant question, then, is
not whether the rate can be adjusted later in a Section 205
hearing – but instead whether a transmission owner can be
forced to accept generator-funded upgrades in the first instance.
That question is squarely before us; we return it to FERC for a
more thorough answer.

On a related point, the dissent suggests that since the
Commission plans to take up the issue of generic
interconnection costs in a pending rulemaking, it is unnecessary
for us to consider Petitioners’ concern in this case. The dissent
implies that FERC has consciously chosen a specific “manner of
proceeding, addressing capital costs here and generic
interconnection cost issues in a separate docket.” Dissent at 9.

The Commission did not make this argument before us, and
for good reason: the purported plan to separate capital costs
from other cost issues is fiction. (In fact, FERC’s sole mention
of its separate rulemaking in the proceedings below was to
acknowledge and reject the Petitioners’ request to avoid
adjudication while the rulemaking was in progress. See
December 2015 Order PP 40, 60.) In the referenced rulemaking
– Docket No. RM15-21 – FERC requested comments on
Intervenor AWEA’s proposals for changes to the standard
interconnection agreements. See Notice of Petition for
 24

Rulemaking, Docket No. RM15-21 (FERC July 7, 2015). And
those proposals explicitly include, in multiple locations, the
precise issue of capital cost allocation.16 This is unsurprising; as
explained at length above, the two issues are deeply intertwined.

Further, even assuming that FERC had intended such a
“manner of proceeding” (and that such a dichotomy would be
conceptually tenable), the dissent’s wait-and-see suggestion
confuses adjudication – which is retroactive, determining
whether a party violated legal policy – with rulemaking, which
is of only future effect. We once described an agency’s effort to
offer future rulemaking as a response to a claim of agency
illegality as an “administrative law shell game,” Am. Tel. & Tel.
Co. v. FCC, 978 F.2d 727, 732 (D.C. Cir. 1992), a phrase the
Supreme Court thought apt. See MCI Telecomm. v. Am. Tel. &
Tel. Co., 512 U.S. 218, 222 (1994).

IV.

When we remand orders to FERC, two factors inform our
decision whether to vacate: the gravity of the orders’ flaws, and
the “disruptive consequences” that may result. Black Oak
Energy, LLC v. FERC, 725 F.3d 230, 244 (D.C. Cir. 2013)

16
See Petition for Rulemaking of the American Wind Energy
Association to Revise Generator Interconnection Rules and
Procedures, Docket No. RM15-21 (FERC June 19, 2015) at 5
(“Reforms to improve certainty of network upgrade costs: . . . ii.
Allow a Transmission Provider to fund network upgrades (self-
funding) only if agreed to by the Interconnection Customer.”); id. at
50-52 (recommending that “The GIPs Should Require the
Interconnection Customer’s Agreement for the Interconnecting
Transmission Owner to Self-Fund Network Upgrades,” id. at 50).
 25

(quoting Allied-Signal v. Nuclear Regulatory Comm’n, 988 F.2d
146, 150-51 (D.C. Cir. 1993)).

As noted above, we have no need to finally decide the
transmission owners’ central complaint in this case: that under
the Federal Power Act and the Constitution, FERC cannot force
them to construct and operate generator-funded network
upgrades.17 Indeed, we should not do so until the Commission
has developed a record by considering that question itself. But
we are troubled by the prospect of allowing the orders to
continue in the interim.

The transmission owners complain that generator-funded
upgrades draft them into service to manage non-profit
appendages to their network; we today remand in part because
FERC failed to respond to that argument. By approving changes
to the MISO tariff, however, the August 2016 Order on
Compliance opens the floodgates to involuntary generator-
funded interconnection projects.18 And we must bear in mind

17
Nor is it necessary to reach the petitioning transmission owners’
argument that FERC departed from its precedent without justification,
or that its orders here are illegal because they constitute a “novel”
form of ratemaking under Hope. These issues may become
appropriate for our consideration in the event that FERC adequately
supports its decision.
18
We think it noteworthy here that FERC, the petitioning
transmission owners, and the intervening independent generators have
all recognized that many interconnecting generators would prefer to
use generator funding if permitted by FERC. And as one engineer
noted before FERC, the backlog of new projects is high, causing a
situation in which “Otter Tail and its neighboring transmission
systems are rapidly confronting the need to fund and construct both
 26

that the Commission’s June 2015 Order indicates that its logic
in this case would apply to all indirect upgrades as well. FERC
may determine on remand that a transmission owner’s consent
is required to impose generator-funded network upgrades, or
that it would be unjust or unreasonable to force the transmission
owners to accept increased risk with no increased return. If it
does not, Article III courts may subsequently require it to do so.
In that event, what will happen to the projects that have
commenced in the interim? How will the generators, who under
the Commission’s logic will presumably have obtained funding
from the capital markets, extricate themselves from those newly-
invalid contracts? Will the financiers with whom they deal
insert clauses imposing costly “break-up fees,” in anticipation of
the ultimate resolution of this question? Or worse: will half-
completed projects be left stranded because they were
financially viable when generator-funded, but become
unprofitable when they bear the full cost of the attendant risks
under transmission owner funding?

We think it at least uncertain that FERC can reach the same
result after addressing the deficiencies identified in this opinion;
indeed, the potential-discrimination justification for FERC’s
orders seems especially weak. But we think the prospect of
disruptive consequences cuts decisively against the premature
approval, and precipitate commencement, of construction
projects under a tariff of questionable legality. Moreover, that

direct and indirect Network Upgrades for new generation.” Affidavit
of Dean Pawloski, Principal Engineer, Otter Tail Power Company at
P 6 (January 12, 2015). The prospect, then, that today’s network
upgrades will cumulatively constitute a significant fraction of
tomorrow’s grid renders the petitioning transmission owners’ concern
more credible.
 27

FERC plans a rulemaking to consider interconnection problems
and costs also suggests that it should approach those issues on
a clean slate. We therefore vacate the orders – with the
recognition that the Commission may, as always, file a petition
for rehearing in the event it objects to such vacatur on ground
we do not perceive – and remand for further proceedings
consistent with this opinion.

So ordered.
 ROGERS, Circuit Judge, dissenting: After the Federal
Regulatory Commission rejected a transmission owner’s
request for unilateral authority to select the funding method for
“network upgrades,” certain transmission owners (hereinafter
“Ameren”) did not prevail on rehearing and now petition for
review of five orders of the Commission.1 In those orders, the
Commission addressed the recovery of capital costs and
determined there were three fundamental problems with
allowing transmission owners unilateral discretion to select the
method of funding network upgrades. First, “it [would] allow[]
the transmission owner . . . [to] subsequently assess the
interconnection customer [hereinafter “generator”] a network
upgrade charge that is not later reimbursed . . . , which may
result in discriminatory treatment by the transmission owner of
different [generators].” June 2015 Order P 48. Second, it
would allow the transmission owner to “deprive the [generator]
of other options to finance the cost of the network upgrades that
provide more favorable terms and rates.” Id. Third, in contrast
to generator funding in which the generator posts security over
the term of construction, transmission owner funding would
require “the [generator] to post security . . . over the term of the
construction phase and over the term of the” contract. Id. P 49.
Such increased costs, the Commission found, may “frustrate

1
Four orders denied rehearing; a fifth order addressed
compliance. Midcontinent Independent System Operator, Inc.,
Order Denying Rehearing, Granting in Part and Denying in Part
Complaint, and Instituting Section 206 Proceeding, 151 FERC ¶
61,220 (June 18, 2015) (“June 2015 Order”); Otter Tail Power
Company v. Midcontinent System Operator, Inc., Order Denying
Rehearing and Granting Clarification, and Directing Compliance
Filing, 153 FERC ¶ 61,352 (Dec. 29, 2015) (“December 2015
Order”); Otter Tail Power Company v. Midcontinent System
Operator, Inc., Order Denying Rehearing, 156 FERC ¶ 61,099 (Aug.
9, 2016) (“August 2016 Order”); Midcontinent System Operator,
Inc., Order on Compliance, 156 FERC ¶ 61,098 (Aug. 9, 2016);
Midcontinent Independent System Operator, Inc., Order Denying
Rehearing, 157 ¶ 61,013 (Oct. 7, 2016).
 2
the development of new, competitive generation, which would
contradict a stated purpose of Order No. 2003.” Id. Indeed,
adding such cost “with no corresponding increase in service,”
the Commission observed, “shares similar characteristics” to a
funding option that the Commission had eliminated as unjust
and unreasonable. Id. (citing E.ON Climate & Renewables
North America, LLC v. Midwest Indep. Transmission Sys.
Operator, Inc., 137 FERC ¶ 61,076, P 37 (2011) (“E.ON”)).

On appeal, Ameren principally contends that the
Commission’s action is confiscatory insofar as it denies
Ameren the ability to earn a return on network upgrades and
fails to compensate Ameren for business risk. Petrs Br. 30-35.
Ameren maintains that the challenged orders fail to address its
most important concern, namely, that absent gaining generator
consent, the orders “force [Ameren] to construct, own, and
operate transmission facilities without any return, i.e., on a
non-profit basis.” Id. at 37-38. The court vacates the
challenged orders, concluding that “there is neither evidence
nor economic logic supporting [the Commission’s]
discriminat[ion] theory as applied to transmission owners
without affiliated generation assets,” and that the Commission
failed to respond adequately to Ameren’s non-profit objection.
Op. at 3, 21-22. For the following reasons, I respectfully
dissent.

I.

As a preliminary matter, it is worth acknowledging the
limited scope of the court’s review of Commission orders.
“[I]n a technical area like electricity rate design,” courts must
“afford great deference to the Commission in its rate
decisions.” FERC v. Elec. Power Supply Ass’n, 136 S. Ct. 760,
782 (2016) (quoting Morgan Stanley Cap. Grp., Inc. v. Pub.
Util. Dist. No. 1 of Snohomish Cty., 554 U.S. 527, 532 (2008)).
 3
As in other agency cases, courts do not “ask whether a
regulatory decision is the best one possible or even whether it
is better than the alternatives,” but instead ask whether “the
agency has ‘examine[d] the relevant [considerations] and
articulate[d] a satisfactory explanation for its action[,]
including a rational connection between the facts found and the
choice made.’” Id. at 782 (quoting Motor Vehicle Mfrs. Ass’n
v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)).
Under the Federal Power Act, factual findings of the
Commission that are supported by substantial evidence in the
record are “conclusive.” 16 U.S.C. § 825l(b); see also Colo.
Interstate Gas v. FERC, 599 F.3d 698, 704 (D.C. Cir. 2010).
Furthermore, this court has recognized that it is “perfectly
legitimate for the Commission to base its findings . . . on basic
economic theory,” as long as “it explain[s] and applie[s] the
relevant economic principles in a reasonable manner.”
Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 531 (D.C.
Cir. 2010).

By way of background to understanding the
Commission’s ongoing consideration of cost allocation in the
Midwest region, the critical undisputed fact is that under the
Midcontinent System Operator (“MISO”) Tariff, generators
bear 90 to 100 percent of the costs of construction of network
upgrades. The Commission determined in 2003 that when the
generator funds the network upgrade, the generator is to receive
credits against transmission service for the amounts funded.
Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, 104 FERC ¶ 61,103 P 28, 694
(2003) (“Order No. 2003”). The Commission, however,
allowed regional transmission organizations “flexibility as to
the specifics of the interconnection pricing policy.” Id. P 28.
Under MISO’s Tariff, transmission owners provided a credit
for 50% of the costs borne by generators that funded network
upgrades. Midwest Independent Transmission System
 4
Operator, Inc., 129 FERC ¶ 61,060, P 3 (2009) (“Midwest ITO
2009”). This changed in 2009. The Commission, acting in
“recogni[tion] that cost allocation is one of the most difficult
and contentious issues facing the Midwest ISO regional at this
time,” id. P 2, approved a proposal by MISO and its
transmission owners (including Ameren) to amend MISO’s
Tariff, id. P 48, “conditioned upon” the filing of a tariff with “a
cost allocation methodology . . . as [was] just and reasonable
and not unduly discriminatory or preferential,” id. P 49. Under
the superseding Tariff, MISO’s Option 2 “increase[d] the cost
responsibility of a[] [generator] to 100 percent of the Network
Upgrade costs, with a possible 10 percent reimbursement for
projects that were 345 kV and above.” Id. P 3.

II.

In the first of the challenged orders, the Commission, in
again addressing the contentious issue of cost allocation in this
section 206 proceeding, rejected the request of a transmission
owner (“Otter Tail”) for unilateral discretion to choose the
funding method for network upgrades. The Commission
determined that such discretion could allow transmission
owners to discriminate against generators through the
imposition of increased costs, thereby “frustrat[ing] the
development of new, competitive generation.” June 2015
Order PP 48-49. Examining Article 11.3 of MISO’s Generator
Interconnection Agreement, the Commission reasoned that the
provision appeared unjust and unreasonable and unduly
discriminatory or preferential because “it allows the
transmission owner the discretion to elect to initially fund the
upgrades and subsequently assess the [generator] a network
upgrade charge that is not later reimbursed . . . through . . .
credits,” and it “may deprive the [generator] of other options to
 5
finance the cost of network upgrades that provide more
favorable terms and rates.” Id. P 48.

As Joint Intervenors point out, MISO’s post-2009 credit
policy is “[a] primary reason” the Commission determined that
such unilateral discretion was unjust and unreasonable and
unduly discriminatory. Jt. Intervenors’ Br. 11 (citing June
2015 Order P 3). Intervenors elaborate that by asking for a
revised MISO-specific credit policy in 2009 and abandoning
responsibility for financing network upgrades, MISO
transmission owners “gave up the opportunity to earn a rate of
return on the network upgrades.” Id. at 12; see August 2016
Order P 15. Now the generator “bears the full cost of the
network upgrades,” save for at most 10%, and the transmission
owner “has no asset to roll in its rate base to earn a rate of
return.” Jt. Intervenors’ Br. 12; see August 2016 Order P 12.
MISO’s credit policy imposes significant costs on generators:
for example, a generator required to fund a $10 million network
upgrade, would receive at most $1 million in credits. Jt.
Intervenors’ Br. 12. Consequently, the credit policy can “cost
the [generator] tens of millions of dollars more than the basic
Order No. 2003 construct.” Id. at 11-12. To this extent, then,
by seeking a MISO-specific tariff amendment, transmission
owners’ inability to earn a return on generator funding is of
their own doing. As Intervenors note, Ameren could earn a
return were MISO to revert back to the crediting scheme under
Order No. 2003. Id. at 13.

On rehearing, the Commission rejected Ameren’s
arguments that there was insufficient evidence of
discrimination and that the incremental risk of new generator-
funded network upgrades would force them to operate on a
 6
nonprofit basis.2 The Commission reaffirmed its determination
that transmission owners’ unilateral discretion over initial
funding “would improperly impose costs on [generators].”
December 2015 Order P 29. Because generators “bear between
90 to 100 percent of the costs for network upgrades in MISO,”
the Commission explained, “it stands to reason that
[generators] would have the incentive to find the lowest cost
solution to funding” such upgrades. Id. at P 56. Conversely,
transmission owners have an incentive to increase costs for the
very reason Ameren has challenged the Commission’s orders:
it seeks a return on top of the cost of the network upgrades. See
Id. P 59; June 2015 Order P 48. Thus, as Intervenor American
Wind Energy Association pointed out in comments of
September 30, 2015 to the Commission, where the generator
pays for the upgrade plus a return on 100% of the “capital
invested by the transmission owner collected over time, such
as a 20 or 30 year period[,]” “[s]imple math shows that self
funding [by a transmission owner] is more costly to the
[generator].” Ameren does not dispute the Commission’s key
determination ― that generators have an incentive to find
lowest cost funding solutions, while transmission owners do
not ― and has provided no basis for the court to disturb the
Commission’s findings and determinations.

The Commission reasonably responded to Ameren’s
argument that removal of transmission owners’ unilateral
discretion over initial funding improperly deprived it of the
ability to recover prudently-incurred transmission costs of
service from generators beyond the capital costs of the network
upgrades. For instance, the Commission rejected the argument

2
Request for Reh’g of the Certain MISO Transmission Owners
(Jul. 20, 2015); Request for Reh’g of the Indicated Transmission
Owners (Jan. 28, 2016); Request for Reh’g of the Indicated
Transmission Owners (Sept. 8, 2016).
 7
that the initial funding option under Article 11.3 of MISO’s pro
forma tariff allows transmission owners to recover non-capital
costs as contrary to its precedent in Midcontinent Independent
System Operator, Inc., 145 FERC ¶ 61,111 at P 41 (2013)
(“Hoopeston”), in which it had determined that doing so would
be “unduly discriminatory” because a generator “charged
under Option 2 would only be required to pay for the capital
costs of network upgrades.” December 2015 Order P 57. The
Commission pointed out that Ameren will recover its cost of
service through its transmission rates, which will be charged to
generators as they take service on the owner’s system. Id. P 57
& n.118 (citing Ameren’s Attachment O rate formula
template). Significantly as well, the Commission rejected the
argument that its “proposed Tariff language would not allow
transmission owners to ‘set’ a rate of return to directly assign
compensation for business risk, such as lawsuits, reliability
compliance obligations, environmental and construction risks,
to a [generator], inasmuch as such business risk associated with
owning transmission are even included in a transmission
owner’s return . . . under the initial funding option.” Id. P 59
(emphasis added). And the Commission observed that “[t]o the
extent MISO believes that the mutual agreement aspect of the
[revised] initial funding option raises concerns about the
impact of certain costs on particular transmission owners and
their customers, MISO may file a proposal under section 205
of the FPA to address such concerns.” Id. P 57. In addition,
the Commission noted that it was “simultaneously considering
generic interconnection cost issues in a separate rulemaking
proceeding in Docket No. RM15-21,” emphasizing that now it
was only finding MISO’s Tariff “unjust and unreasonable and
unduly discriminatory based on the record before us here.” Id.
P 60.

Balancing risks in allocating costs, the Commission
determined that Option 2 was a just and reasonable rate and
 8
available under MISO’s Tariff, noting that Ameren “ignores
the continued existence of the transmission owner’s initial
funding option” by mutual agreement with the generator.
December 2015 Order P 59. It emphasized that “the obligation
to fund these network upgrades rests with the [generator] under
MISO’s Tariff and as credits are not provided in return for this
funding, we find that it is potentially unjust, unreasonable and
unduly discriminatory to deprive the [generator] of the ability
to provide its own capital funding.” Id. P 59. Citing FPC v.
Hope Natural Gas Co., 320 U.S. 591 (1944), the Commission
acknowledged that its “task is to allow a public utility the
opportunity to offer its investors a return that is commensurate
with the risk associated with their investment, as represented
by the utility’s business and financial risks.” August 2016
Order P 13. It found that where generator funding is used, “the
[generator] making the up-front investment bears the business
and financial risks associated with financing and constructing
the network upgrades.” Id. “Because the transmission owner
does not bear that risk,” the Commission determined that “its
investors are not exposed to that risk, and it is therefore not
necessary for the transmission owner to offer investors a return
based on that risk in exchange for their investment of capital.”
Id.

The Commission observed further that Ameren “does not
allege that funding for network upgrades under Option 2 is
confiscatory inasmuch as it provides an insufficient rate of
return to a transmission owners; rather, [Ameren] take[s] issue
only with the fact that [it] will no longer unilaterally elect that
financing option.” Id. P 15 (emphases added). Additionally,
the Commission determined, Ameren “had not shown how
requiring [a generator] to post security to address risk during
construction and allowing [a generator], as opposed to the
transmission owner, the initial opportunity to fund network
upgrades, precludes transmission owners from operating
 9
successfully, maintaining financial integrity, attracting capital,
and compensating investors for the risks assumed, in violation
of Hope.” Id. P 16. Were Ameren in fact to incur
uncompensated costs, such proof could be presented in a future
proceeding. See December 2015 Order P 57; see also id. P 60.

III.

The court nevertheless concludes that the challenged
orders must be vacated. Op. at 27. The reasons offered by the
court for vacatur are unpersuasive because the so-called
“deficiencies,” id. at 26, simply ignore the Commission’s
analysis and Ameren’s failure to produce evidence of
uncompensated risks as well as the Commission’s manner of
proceeding, addressing capital costs here and generic
interconnection cost issues in a separate docket. The
challenged orders reflect the Commission’s determination
upon assessing a complex and difficult balancing of risks in
regard to recovery of costs, and the court owes deference to the
Commission’s expertise and technical understanding. See
Elec. Power Supply Ass’n, 136 S. Ct. at 784.

A.
The court faults the Commission for failing to show why a
transmission owner without affiliates would discriminate
among generators. Op. at 12-13. But Ameren never argued
this point to the Commission. See Request for Reh’g of the
Certain MISO Transmission Owners (Jul. 20, 2015); Request
for Reh’g of the Indicated Transmission Owners (Jan. 28,
2016); Request for Reh’g of the Indicated Transmission
Owners (Sept. 8, 2016). Nor did Ameren argue that the
Commission’s determination regarding generator funding
should be limited to transmission owners with affiliates (such
as “Ameren Missouri”). See Op. at 12-13. Ameren disputed
only the Commission’s determination that undue
 10
discrimination may occur if transmission owners could
unilaterally elect to fund network upgrades. The court insists
that Ameren’s incentive theory “can hardly be thought a new
argument” given Ameren’s “vigor[]” in broadly claiming there
was no evidence of discrimination. Op. at 13. But an implicit
argument about incentives does not meet the statutory
requirement and the court offers no pertinent record citation.
This court’s jurisdiction is limited to grounds “‘set forth
specifically’ in the petitioner’s request for Commission
rehearing.” Ind. Util. Reg. Comm’n v. FERC, 668 F.3d 7325,
739 (D.C. Cir. 2012) (quoting 16 U.S.C. § 825l(a)); see Kelley
ex rel. Mich. Dep’t of Nat. Res. v. FERC, 96 F.3d 1482, 1487-
88 (D.C. Cir. 1996). The court, therefore, vacates the orders
based in part on an argument that the Commission never had
the chance to consider and over which the court, therefore,
lacks jurisdiction. 16 U.S.C. § 825l (b).

That procedural default aside, the court could hardly
dispute that Ameren has “a competitive motive” to favor
affiliated generators over other generators. The Commission
addressed this circumstance in Order No. 888 and the Supreme
Court thereafter observed that “utilities’ control of
transmission facilities gives them the power either to refuse to
deliver energy produced by competitors or to deliver
competitors’ power on terms and conditions less favorable than
those they apply to their own transmissions.” New York v.
FERC, 535 U.S. 1, 8-9 (2002); see Nat’l Ass’n of Reg. Utility
v. FERC, 475 F.3d 1277, 1279 (D.C. Cir. 2007). The court
recognized in a monopoly context that transmission owners
“naturally wish to maximize profit” and “can be expected to act
in their own interest . . . even if they do so at the expense of
lower-cost generation companies and consumers.”
Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667,
684 (D.C. Cir. 2000). The Commission has identified a similar
motivation in its interconnection precedent in determining, in
 11
view of MISO’s post-2009 credit policy, that unilateral
transmission owner control over initial funding of upgrades
“creates unacceptable opportunities for undue discrimination.”
E.ON, 137 FERC ¶ 61,076, P 38. So too in the challenged
orders. In short, even if the court had jurisdiction, its vacatur
is overbroad.

This court has recognized that the Commission may
properly take action “premised not on individualized findings
of discrimination by transmission providers, but on a
fundamental systemic problem.” Transmission Access Policy
Study Grp, 225 F.3d at 684. Here, the Commission was
confronted with the fundamental, systemic problem of the
recovery of capital costs, see August 2015 Order P 17, where
transmission owners had threatened to withdraw from a
regional organization, see Midwest ITO 2009, P 7, and now
sought to impose increased costs on generators without
increasing service based on a unilateral discretionary choice of
the method of funding network upgrades. June 2015 Order P
52. As discussed, the Commission identified the contrasting
economic motivations of transmission owners and generators,
see, e.g., December 2015 Order PP 29, 56, 59; June 2015 Order
P 48, in determining that the transmission owner funding
option would involve imposition of a network upgrade charge,
June 2015 P 48, and a more onerous security requirement,
December 2015 Order P 29, and loss to generators of the
opportunity to secure more favorable financing, id.

In addition to relying on “reasonable economic
propositions,” see S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41,
65 (D.C. Cir. 2014), and its precedent, the Commission pointed
to empirical evidence that transmission owners’ unilateral
election to initially fund network upgrades could result in
increased costs to generators or be implemented in an unduly
discriminatory way. The Commission looked to the Border
 12
Winds protest where evidence was introduced that a
transmission owner’s initial funding election increased the
costs to the generator. December 2015 Order P 33. The court
characterizes the study as “flawed,” Op. at 12 n.10, but this is
an overstatement. The Commission itself recognized that the
transmission owner’s proposed fixed rate was not calculated in
conformity with a clarification in Commission precedent but
concluded “the case record in Border Winds” nonetheless
showed increased generator costs, because Border Winds never
indicated that a “lower fixed charge rate . . . would still not
represent an increase in cost compared to” generator funding.
December 2015 Order P 33. Further, the Commission pointed
out, its clarifying precedent had not considered the effect of a
transmission owner’s unilateral election of initial funding on
relative capital costs. See id. P 34.

Indeed, the court acknowledges that “it is certainly
possible, if not probable” that generators could be deprived of
less costly financing options. Op. at 15; see June 2015 Order
P 49; Jt. Intervenors’ Br 13-14 (citing comments of Intervenor
American Wind Energy Association). Yet the court dismisses
without serious engagement, see Op. at 15-16, the
Commission’s extended consideration of the difficulties
presented by cost allocation in the Midwest region, see
Midwest ITO 2009, P 2, aggravated by MISO’s post-2009
credit policy, as well as the Commission’s determination to
adhere to the principles underlying Order No. 2003, so as to
prevent undue discrimination, preserve reliability, increase
energy supply, and lower wholesale prices for customers by
increasing competition, and its interconnection precedent in
Hoopeston and E.ON to ensure transmission owners could not
unilaterally increase costs to generators.
 13
B.
The court also raises the specter of additional
uncompensated risks and concludes the Commission
“inadequately considered” Ameren’s argument. Op. at 17.
Were this so, then a remand for further explanation, not
vacatur, would be appropriate. See Allied-Signal v. Nuclear
Reg. Comm’n, 988 F.2d 146, 151 (D.C. Cir. 1993). But it is
not so. The court concludes the Commission “makes no real
attempt to holistically assess all of the various risks and
benefits to the transmission owner caused by the addition of the
upgrade facilities.” Op. at 16. That, at best, is an
overstatement. The court’s analysis is doubly flawed.

First, the Commission’s response is understandable
because Ameren offered only bare generalities about its
uncompensated costs, but no specifics. December 2015 Order
P 59. In seeking rehearing, Ameren referred broadly and baldly
to concern about “lawsuits, reliability compliance obligations,
environmental risk, and construction risk, among others.”
Request for Reh’g of the Indicated Transmission Owners (Sept.
8, 2016), at 13. In a footnote, the court labors unsuccessfully
to recast Ameren’s general claims as specific ones. See Op. at
17 n.14. Absent any evidence of specific uncompensated costs,
however, what Ameren presented to the Commission was a
claim for generic relief that was being addressed in a separate
docket. December 2015 Order PP 40, 60. The court’s reliance,
Op. at 24, on American Telephone & Telegraph Co. v. FCC,
978 F.2d 727, 729 (D.C. Cir. 1992), is misplaced. Here there
was no “administrative shell game.” Id. at 731-32. The
Commission stood ready to address Ameren’s business risk
claims but was stymied from doing so in this adjudicatory
proceeding because Ameren failed to present any specific
evidence. In deciding to address generic claims in a separate
proceeding, the Commission was “merely exercising its well-
established discretion to ‘order [its] own docket[].’” Algonquin
 14
Gas Transmission. Co. v. FERC, 948 F.2d 1305, 1315 (D.C.
Cir. 1991) (alterations in original); see U.S. Tel. Ass’n v. FCC,
359 F.3d 554, 588 (D.C. Cir. 2004).

Second, the court ignores that Ameren never points to any
explanation it offered to the Commission of how it faced any
additional insurance, construction, or environmental risk as a
result of a particular funding method over another. It is
undisputed that under MISO’s Tariff, as the Commission
found, Ameren as a transmission owner is compensated for
operational and management costs. December 2015 Order P
47 n.118 (citing MISO, FERC Electric Tariff, att. O).
Transmission owners are also required to purchase Employers’
Liability and Workers’ Compensation Insurance, Commercial
General Liability Insurance, Comprehensive Automobile
Liability Insurance, and Excess Public Liability Insurance
regardless of how network upgrades are funded. MISO, FERC
Electric Tariff, att. X, app. 6 (GIA) § 18.4 (minimum insurance
requirements). Generators, in turn must post security, under
MISO’s Tariff, “in order to address risk during construction.”
December 2015 Order P 59. Ameren does not suggest the risk
of an environmental violation is anything other than equal
under either initial funding method. In the Commission’s
words:

Indicated MISO Transmission Owners have not
explained how allowing [a generator] to fund network
upgrades under Option 2 fails to protect against
unspecified ‘other risks associated with construction
(not otherwise addressed by insurance)’ or operating
risks due to requirements “to operate customer-
financed assets in compliance with applicable
Reliability Standards,” violations of which could
“result in penalties that would not be recoverable from
customers.”
 15

August 2016 Order P 17 (quoting Request for Reh’g at 22).

Furthermore, the Commission determined that network
upgrades could mitigate transmission owners’ reliability risk
by reducing congestion. August 2016 Order P 17. In the post-
Order No. 888 context, this court has recognized that network
upgrades “provide system-wide benefits.” NARUC, 475 F.3d
at 1285. The court characterizes the benefits of network
upgrades as “a possibility to be explored,” Op. at 17, rather than
a determination to which the court owes deference. This
misses the mark. The Commission’s point was that in view of
the acknowledged benefits of network upgrades, Ameren had
not explained how network upgrades “should be considered
additive to the reliability risk,” August 2016 Order P 17, much
less shown that it faced additional reliability risk as would
justify setting aside the challenged orders as confiscatory. The
determination that Ameren had not shown additional reliability
risk deserves deference.

Having failed to identify any unrecoverable additional
costs traceable to the challenged orders, Ameren attempts to
shift its “heavy” burden on rehearing, see Hope, 320 at 602, by
contending that the Commission “ignores the fundamental
reality that all new facilities bring incremental risk of
operation.” Reply Br. 22. Of course, that simply elides the
question of whether there are any risks that are uncompensated,
for not every regulatory decision requiring action by a
regulated entity gives rise to a corresponding entitlement to a
return ― “regulation does not insure that the business shall
produce net revenues.” Hope, 320 U.S. at 603 (internal
quotation marks omitted). The court accepts that allowing
generators to select the initial funding method “might remain
bearable so long as the generator-funded upgrades growing
inside the grid remain tiny relative to their host.” Op. at 20.
 16
And although the Commission acknowledges that independent
power generators have an increasing presence since Order No.
888, Rspdt’s Br. 4, the Commission’s statutory concern is that
“competition depend[s] on generators’ having adequate means
of getting their power to market.” NARUC, 475 F.3d at 1279
(internal citation omitted). Unbundling under Order No. 888
required equal access for generators to transmission facilities,
see id., and in Order No. 2003, the Commission standardized
procedures for generator interconnections. The challenged
orders reflect adherence to those principles.

Under the circumstances, there is no basis for the court to
state that the Commission made “no real attempt to holistically
assess” risks and benefits, Op. at 16, given Ameren’s
evidentiary failure, the Commission’s determination regarding
reliability risk, and its broader analysis of the allocation issue
based on the record before it. Instead, the court has ignored
inconvenient record facts and the Commission’s fulsome
response to Ameren’s arguments, including its explicit
statement on the limits of its ruling on MISO’s Tariff in the
challenged orders. December 2015 Order P 60. The
Commission’s assessments of how the risks should be balanced
in allocating capital costs is a quintessential task involving
Commission expertise and technical understanding that is
entitled to deference by the court. See Elec. Power Supply
Ass’n, 136 S. Ct. at 784.

C.
The court also mistakenly accepts Ameren’s bald assertion
that the challenged orders will force transmission owners to
operate on a nonprofit basis in violation of Hope. Op. at 18-
22. In Hope, the Supreme Court addressed whether natural gas
rates threatened a company’s overall financial integrity; it
nowhere suggested that the Federal Power Act entitled a
company to the ability to earn a favorable return on every
 17
portion of its business. See Hope, 320 U.S. at 605. Addressing
a similar issue under a state statute, the Supreme Court made
clear that the focus was on whether “[t]he overall impact of the
rate orders” would “jeopardize the financial integrity of the
companies.” Duquesne Light Co. v. Barasch, 488 U.S. 299,
310 (1989). The court here acknowledges that “[i]nvestors . . .
invest in entire enterprises, not just portions thereof.” Op. at
19. Why that is not also a permissible perspective for the
Commission when weighing risks relating to the recovery of
capital costs is not explained.3

The issues now before the court are whether the
Commission reasonably determined under the Federal Power
Act, based on the evidence presented, that it is (1) unduly
discriminatory to allow transmission owners unilaterally to
select a financing scheme that increases costs for a generator
seeking interconnection services, and (2) just and reasonable to
allow a generator to choose to pay the upfront capital costs of
network upgrades required for interconnection, with the result
that those capital costs are excluded from the transmission
owner’s rate base. The court appears to assume that generator-
funded upgrades will comprise a “significant fraction” of
Ameren’s overall business. Op. at 25 n.18. But the court points

3
The court’s chastisement of the Commission, based on its
counsel’s purported response to a hypothetical question during
oral argument before the court, is misplaced. The court
suggests that counsel “cross[ed] a rather significant conceptual
line” by agreeing that transmission owners would not be
entitled to a return on a billion-dollar network upgrade. Op. at
20-21. But the transcript shows that Commission counsel
stated that transmission owners could seek a “profit” in such a
future case if there were an “evidentiary basis” that the upgrade
posed a “demonstrated specific risk.” Oral Arg. at 39:30-
40:51.
 18
to no Ameren financial data that would support its prediction
that the Commission’s decision unlawfully interferes with
Ameren’s “business model.” Op. at 18. An affidavit it cites
from the Otter Tail Power Company describing a number of
upcoming interconnection projects, see Op. at 25 n.18, hardly
suffices to carry Ameren’s “heavy” burden on rehearing to
disturb the Commission’s balancing of risks. See Hope, 320 at
602.

D.
The court’s discounting of the Commission’s reference to
Ameren’s opportunity to present evidence of uncompensated
risks in a future proceeding, Op. at 22-23; December 2015
Order P 57, fares no better. The court states that “fines and
penalties for violations of mandatory reliability standards and
environmental regulations are generally charged directly to the
utility, not passed through to customers via rate increases.” Op.
at 21; see Pet’rs Br. 33 n.1. The stipulated agreement in In re
SCANA Corp., 118 FERC ¶ 61,028 (2007); see Op. at 22,
nowhere suggests fines and penalties are unrecoverable as a
matter of law. Even assuming the general practice is that fines
and penalties are not passed on, the court cites no authority the
Commission erred as a matter of law in holding out the
evidentiary opportunity for Ameren. See Op. at 22. The
Commission’s rejection of Ameren’s arguments as to
uncompensated business risks and forced “non-profit”
operation rested on Ameren’s failure to proffer specific
evidence. See August 2016 Order PP 16-17. Given the
Commission’s stated position in the challenged orders, there is
no basis for the court to conclude the outcome of a future
hearing is a “foregone conclusion.” Op. at 23. The court’s
vacatur thus overshoots its target and jumps the gun.
 19
III.

The Federal Power Act mandates the Commission ensure
that rates are “just and reasonable” and not unduly
discriminatory, 16 U.S.C. § 824d(a)-(b). A purpose of Order
No. 2003 is to “increase[e] the number and variety of new
generation that will compete in the wholesale electricity
market.” Order No. 2003 at P 1. Given the established
economic motivations and the post-2009 MISO credit policy’s
treatment of capital costs, the Commission reasonably and
adequately explained its assessment of how risks should be
balanced between investor and customer interests. See Hope,
320 U.S. at 603. The Commission recognized the complex and
contentious nature of the issue in the Midwest region,
conditionally approved the 2009 proposal of MISO and its
transmission owners to amend MISO’s Tariff, and has now,
based on the record before it, determined, in its expert
judgment, that Ameren’s arguments for unilateral control of the
method of funding network upgrades must be rejected and
generators allowed to choose the funding method. The same
two funding options for network upgrades that were available
prior to the challenged orders remain available; the only change
is that the choice belongs to generators with an incentive to
minimize costs rather than to transmission owners with an
incentive to impose additional costs that could frustrate the
development of new generation.

In doubting the adequacy of the Commission’s
determination of the appropriate allocation of capital costs in
MISO, the court asserts that the Commission failed to address
the concern that “when portions of a business are unprofitable,
it detracts from the attractiveness to investors of the business
as a whole.” Op. at 20. But the Commission directly addressed
that concern when it found that Ameren had failed to present
evidence showing a threat to its overall financial integrity as
 20
would warrant finding the challenged orders were confiscatory.
August Order 2016 P 16. Somehow the court overlooks that
Ameren’s laser-like focus is on regaining unilateral control
over funding network upgrades. See August 2016 Order P 15.
Hope does not require this, for reasons the Commission
explained. Commission precedent likewise points the other
way. Absent evidence that the challenged orders will cause
generator-funded network upgrades to occupy so “significant
[a] fraction” of Ameren’s business as would jeopardize its
overall financial integrity, the Commission’s reasons for
rejecting unilateral transmission owner control were not
arbitrary or capricious. Vacating the challenged orders at this
juncture is inconsistent with the record before the Commission,
its findings and determinations in allocating capital costs, and
the court’s deferential standard of review.