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.