United States Court of Appeals

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Argued April 16, 2013 Decided August 6, 2013

No. 08-1386

BLACK OAK ENERGY, LLC, ET AL.,

PETITIONERS

v.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

CITY POWER MARKETING, LLC, ET AL.,

INTERVENORS

Consolidated with 11-1275, 12-1286

On Petitions for Review of Orders of 

the Federal Energy Regulatory Commission

Catherine R. Connors argued the cause for petitioners. 

With her on the briefs were Carol A. Smoots and Timothy R. 

Schneider. 

Samuel Soopper, Attorney, Federal Energy Regulatory 

Commission, argued the cause for respondent. With him on 

the brief were David L. Morenoff, Acting General Counsel, and 

Robert H. Solomon, Solicitor. Beth G. Pacella, Attorney, 
2

Federal Energy Regulatory Commission, Robert V. Eckenrod, 

Gary J. Newell, and Robert A. Weishaar Jr.

Before: GARLAND, Chief Judge, ROGERS and GRIFFITH, 

Circuit Judges.

Opinion for the Court filed by Circuit Judge GRIFFITH.

GRIFFITH, Circuit Judge: By statute, the Federal Energy 

Regulatory Commission (FERC) regulates trading in energy 

markets. This case concerns the markets operated by PJM 

Interconnection LLC, a Regional Transmission Organization 

(RTO)1 covering the East Coast, Appalachia, and parts of the 

Midwest. Some PJM market participants are known as “virtual 

marketers.” Unlike participants who actually traffic in 

electricity, the virtual marketers never deliver or take delivery 

of electricity; they trade in order to profit from price 

fluctuations. 

The petitioners and petitioner-intervenors in this case – all 

virtual marketers – petition for review of two sets of FERC 

orders. The first orders approved PJM’s method for disbursing 

a monetary surplus that results from the way it operates its 

markets. The virtual marketers do not receive any of this large 

pool of money, but they believe they should. To that end, they 

argue that FERC’s orders violate the Federal Power Act (FPA) 

and the Administrative Procedure Act (APA). In Part I, we set 

forth the facts relevant to this petition for review, and in Part II, 

we set forth our reasons for denying it.

 1 RTOs coordinate the transmission of electricity across a 

geographic region. RTOs must be independent of any individual 

market participant and must possess certain forms of control over 

transmission of electricity in the region. See generally Regional 

Transmission Organizations, 89 FERC ¶ 61,285 (1999).
3

The second petition – also brought by a group of virtual 

marketers, albeit a larger set of them – seeks review of FERC’s 

orders requiring PJM to recoup money refunded to the virtual 

marketers in connection with the administrative dispute over 

the surplus. The petitioners and petitioner-intervenors argue 

that these orders also violated the FPA and the APA. In Part III, 

we set forth the facts relevant to this petition and explain our 

reasons for remanding the orders in question to FERC for 

reconsideration. 

I

In the mid-1990s, federal electricity policy took a 

competitive turn. Prior to that time, “utilities were vertically 

integrated monopolies; electricity generation, transmission, 

and distribution for a particular geographic area were generally 

provided by and under the control of a single regulated entity.” 

Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 

1363-64 (D.C. Cir. 2004). Since then, those vertical 

monopolies have broken apart and, in many regions, systems 

utilizing electricity trading markets have sprung up in their 

place. Generators sit at one end of the regional transmission 

process; at the other end sit local utility companies. The 

markets help coordinate and allocate electricity from the 

generators to the local utilities. The market operator involved 

in this case, PJM Interconnection, LLC, is an RTO that uses 

markets to determine pricing and to schedule the transmission 

of electricity across the massive territory in which it operates. 

See Atl. City Elec. Co. v. PJM Interconnection, LLC, 115 

FERC ¶ 61,132, 61,473 (2006). PJM operates two markets 

relevant to this portion of the case: a “Day-Ahead Market” and 

a “Real-Time Market.” 

The vast majority of electricity traded in the PJM markets 

is traded in the Day-Ahead Market, in which traders bid on 
4

electricity to be transmitted the next day. See Black Oak 

Energy, LLC v. PJM Interconnection, LLC, 125 FERC 

¶ 61,042, 61,146 (2008). (Since electricity cannot be 

effectively stored, delivery must be timely.) The Day-Ahead 

market “derives a market-clearing price from the sellers’ and 

buyers’ price and quantity indications for the next day; sales 

are then made at the market-clearing price.” Edison Mission 

Energy, Inc. v. FERC, 394 F.3d 964, 965 (D.C. Cir. 2005). 

PJM then produces a transaction schedule in advance of actual 

production and distribution. See FERC OFFICE OF 

ENFORCEMENT, ENERGY PRIMER: A HANDBOOK OF ENERGY 

BASICS 101 (2012) [hereinafter ENERGY PRIMER]. “The 

day-ahead market allows market participants to . . . hedge 

against price fluctuations that can occur in real-time” due to 

problems such as generator outages, weather events, and 

unforeseen congestion. Id.

Not all electricity is purchased in advance, however. 

Various risk factors upset sellers’ and buyers’ projections of 

supply and demand as manifested in the Day-Ahead schedule. 

In PJM’s Real-Time Market, participants correct for these 

changes by trading electricity at prices quoted for sale and 

delivery within five-minute intervals. See id. at 102. PJM 

calculates these prices based on grid operating conditions and 

submitted bids. See id. PJM then coordinates the supply and 

distribution chain “to meet the instantaneous demand for 

electricity.” Id.

In the Day-Ahead and Real-Time markets, PJM calculates 

prices according to the method of Locational Marginal Pricing

(LMP), which is used by electricity market operators across the 

country. See Sacramento Mun. Util. Dist. v. Cal. Indep. Sys. 

Operator Corp., 616 F.3d 520, 524-26 (D.C. Cir. 2010) (per 

curiam); Wis. Pub. Power, Inc. v. FERC, 493 F.3d 239, 250-51

(D.C. Cir. 2007) (per curiam). Under LMP, the price any given 
5

buyer pays for electricity reflects a collection of costs attendant 

to moving a megawatt of electricity through the system to a 

buyer’s specific location on the grid. 

As we have explained in the past, 

[w]ith an LMP-based rate structure, prices are designed to 

reflect the least-cost of meeting an incremental 

megawatt-hour of demand at each location on the grid, and 

thus prices vary based on location and time. [In an LMP 

system, each price] consists of three components: (i) the 

cost of generation; (ii) the cost of congestion; and (iii) the 

cost of transmission losses.

Sacramento Mun. Util. Dist., 616 F.3d at 524 (citation 

omitted). The cost of generation can be thought of as the 

“baseline cost” of serving electricity (known in the industry as 

“load”) to another location on the system in a hypothetical, 

congestion-free environment. Id. Congestion, in turn, drives up 

costs because it requires PJM to dispatch more expensive 

generators to meet demand. See ENERGY PRIMER at 65. The 

cost of congestion results in different prices at different nodes 

of the system, depending on how congested the wires leading 

to those nodes are. Wis. Pub. Power, Inc., 493 F.3d at 250-51. 

At issue in this case is the cost of “transmission losses,” which 

refers to “the amount of electric energy lost when electricity 

flows across a transmission system . . . .” Sithe/Independence 

Power Partners, L.P. v. FERC, 285 F.3d 1, 2 (D.C. Cir. 2002). 

The losses are a function of “the amount of the current flowing 

on the wire[,] . . . the resistance it encounters,” and the distance 

it travels. Id. Thus, all else equal, at peak demand times, there 

are higher losses, and at low demand times, there are lower 

losses. PJM charges every buyer of electricity to cover these 

transmission losses; we will call that charge the “transmission 

loss component” of an LMP price.
6

For our purposes, there are two relevant ways to calculate 

the transmission loss component of an LMP price: “average 

loss pricing” and “marginal loss pricing.” Whereas average 

loss pricing charges buyers the average cost of transmission 

losses, marginal loss pricing charges buyers the higher, 

marginal cost of transmission losses. (Confusingly, marginal 

loss pricing and LMP are not the same thing. Marginal loss 

pricing is a method for calculating the transmission loss 

component of LMP.) PJM, for a time, used average loss 

pricing, but FERC eventually determined that the method 

inequitably charged long-distance buyers too little, and 

short-distance buyers too much. See Wis. Pub. Power, Inc., 493 

F.3d at 252 (noting the problem with average loss pricing); Atl.

City Elec. Co., 115 FERC ¶ 61,132, 61,473-74 (noting that 

PJM was using the average loss method). FERC therefore 

ordered PJM to implement the marginal loss pricing method. 

See id. at 61,478. Marginal loss pricing “recovers transmission 

losses on a transaction-by-transaction basis by . . . treat[ing] 

every transmission as if it were the last (marginal) transmission 

on the system.” Wis. Pub. Power, Inc., 493 F.3d at 252. This 

method charges each buyer for the last, most problematic load 

transmission during any given time period.

Under the marginal loss method, the effect of losses on the 

marginal cost of delivering energy is factored into the 

energy price (i.e., the . . . LMP) at each location. Other 

things being equal, customers near generation centers pay 

prices that reflect smaller marginal loss costs while 

customers far from generation centers pay prices that 

reflect higher marginal loss costs. In addition, under the 

marginal loss method (and unlike under the current 

average loss system), PJM . . . consider[s] the effects of 

losses in determining which generators to dispatch in 

order to serve load at least cost.
7

Atl. City Elec. Co., 115 FERC ¶ 61,132, 61,474. At the time of 

its adoption, a commenter submitted that the systemic cost 

savings of this method would amount to $100 million a year. 

See id. at 61,478.2

 2 FERC has explained the effect of marginal loss pricing on 

incentives in the following way:

When prices at each location reflect the full marginal cost of 

delivery, (i.e., energy, congestion and losses), customers can 

make efficient choices among suppliers at different locations. 

The full marginal cost of delivering electricity to a customer at 

one location includes the marginal cost of the losses in moving 

the energy from the generator to the customer’s 

location. . . . For example, if the marginal losses to deliver 

energy from a remote generator to a customer at another 

location are 10 percent, then in order to deliver 1 MWh to the 

customer, the remote generator must produce 10 percent more, 

or 1.1 MWh of energy. If the remote generator’s marginal cost 

to produce 1 MWh is $50, then the marginal cost of delivering 1 

MWh of energy to the customer is $55 (i.e., the marginal cost of 

producing 1.1 MWh). Suppose that the customer could be 

served with energy either from the remote generator or from a 

local generator whose losses would be de minimus and whose 

marginal production cost is $53/MWh. If the buyer fails to 

consider, and is not required to pay for, losses, the remote 

generator would appear to be cheaper, since its marginal 

production cost (of $50/MWh) would be lower than the 

$53/MWh marginal production cost of the nearby generator. 

However, when marginal losses are considered, the nearby 

generator would be the more efficient source. That is because 

the marginal cost of delivering energy to the customer from the 

nearby generator would be about the same as the marginal 

production cost of $53/MWh (since losses would be de 

minimus), while the full marginal cost to deliver energy from 

the remote generator would be higher, i.e., $55/MWh. Thus, in 

determining what supply sources can most efficiently serve 
8

But the marginal loss pricing scheme creates an 

administrative challenge. Because “transmission losses 

increase with the amount of current in the system, treating 

every transmission as the marginal transmission produces 

revenue in excess of actual losses . . . .” Wis. Pub. Power, Inc., 

493 F.3d at 252. That is, marginal losses always exceed 

average losses. By charging everyone as if they were 

responsible for the last, most problematic transmission on the 

system, PJM ends up collecting more money – much more 

money – than the amount it actually takes to cover the cost of 

the transmission losses. The resulting surplus, a large pot of 

money held by PJM, has no clear owner. 

This case is a dispute over the obvious question: Who 

should get the money? By statute, PJM takes the first crack at 

an answer because it must file a tariff describing its rates and 

terms of service, one component of which is its plan for 

distributing the transmission loss surplus money. See 16 U.S.C.

§ 824d(c); Sithe/Independence Power Partners, L.P., 285 F.3d

at 4-5 (describing a surplus distribution system as an integral 

part of a tariff). In turn, PJM’s tariffs are subject to approval by 

FERC. See 16 U.S.C. § 824d(a). Though the parties do not 

dispute FERC’s approval of the marginal loss pricing approach 

itself, they dispute its approval of PJM’s system for 

distributing the transmission loss surplus.

 

customers, the cost of marginal losses should be considered. 

Failure to consider marginal losses – or to understate marginal 

loss costs – can inefficiently inflate the total cost of serving 

load. 

Cal. Indep. Sys. Operator Corp. Pub. Util. Providing Serv. in Cal.

Under Sellers’ Choice Contracts, 107 FERC ¶ 61,274, 62,269 

(2004) (emphasis omitted).
9

In its communications with PJM about its tariff, FERC 

was adamant about what PJM should not do when distributing 

the surplus. FERC explained in multiple orders that PJM was 

forbidden from using the money to “reimburse” market 

participants for the initial transmission loss payments. See, 

e.g., Black Oak Energy, LLC v. PJM Interconnection, LLC,

122 FERC ¶ 61,208, 62,184-85 (2008). Traders are smart: 

when they know that their marginal loss payments are going to 

be partially refunded, they will treat the LMP as a mere sticker 

price that masks the true, post-rebate price of each trade, 

distorting the incentives marginal loss pricing is supposed to 

create. To some extent, any system that PJM adopts will alter 

the incentives that traders face, but the more direct the relation 

between the LMP price calculation and the surplus 

disbursement calculation, the more completely the system will 

erode LMP’s incentive structure. To prevent this, FERC 

required PJM to divorce the surplus allocations from the 

amount that market participants pay into the surplus in the first 

place.

Along the road to marginal loss pricing, PJM identified 

several methods for distributing the surplus while complying 

with FERC’s “no reimbursements” constraint. See Atl. City 

Elec. Co. v. PJM Interconnection, LLC, 117 FERC ¶ 61,169, 

61,860-61 (2006). Eventually, FERC approved a system in 

which the surplus would be allocated to market participants 

based on the amount they pay for the fixed costs of the 

transmission grid. See Black Oak Energy, LLC, 122 FERC 

¶ 61,208, 62,185; Black Oak Energy, LLC, 125 FERC 

¶ 61,042, 61,145-48. This system garnered the support of the 

majority of PJM market participants, see Atl. City Elec. Co., 

117 FERC ¶ 61,169, 61,860, but also had its detractors, some 

of whom filed the initial administrative complaint giving rise 

to the orders at issue in this case. See generally FERC Docket 

No. EL08-14 (Dec. 7, 2007).
10

In Part II, we address the petition for review of the orders 

that approve this system and deny requests for reconsideration 

of the approval. (Collectively, we call them the “Surplus 

Orders.”) The parties bringing the petition are a set of 

electricity traders active on the PJM market. They are variously 

referred to in the record and the briefs as “virtual marketers,” 

“financial marketers,” and “arbitrageurs.” We use the term 

“virtual marketers.” Whatever the name, the salient factor that 

distinguishes them from all others who participate in the PJM 

market is that they never actually transmit or take delivery of 

electricity. Rather, their trades are offsetting: when they are 

done trading, they neither owe, nor are they owed, any 

electricity. Instead, they have either profited or lost based on 

price fluctuations in the time between their purchases and their 

sales. The virtual marketers pay none of the fixed costs of the 

grid.

3 As a result, under the system FERC approved, the 

virtual marketers receive no surplus allocation. They petition 

for review of FERC’s orders approving that outcome. We deny 

their petition for review.4

II

The virtual marketers argue that FERC’s orders selecting a 

transmission loss surplus allocation system violate 16 U.S.C. 

§ 824d, which requires that “all rules and regulations affecting 

or pertaining to . . . rates or charges shall be just and 

 3 This was not always the case. See discussion infra note 6 and 

accompanying text.

4 Because we so hold, we need not address the petition for 

review of FERC’s denial of the virtual marketers’ Second 

Complaint, which concerned the scope of potential refunds. See 

EPIC Merchant Energy NJ/PA, L.P. v. PJM Interconnection, LLC, 

131 FERC ¶ 61,130 (2010).
11

reasonable,” § 824d(a), and prohibits FERC from approving a 

tariff that grants “undue preference or advantage to any person 

or subject[s] any person to any undue prejudice or 

disadvantage, or . . . maintain[s] any unreasonable difference in 

rates . . . as between classes of service,” § 824d(b). In 

reviewing each challenge, we apply the familiar arbitrary and 

capricious standard to FERC’s actions. See Sacramento Mun.

Util. Dist., 616 F.3d at 528, 533-35 (applying the 

arbitrary-and-capricious framework to § 824 review); W. Area 

Power Admin. v. FERC, 525 F.3d 40, 57-58 (D.C. Cir. 2008)

(describing § 824 review as arbitrary-and-capricious review). 

Under this “highly deferential” standard, see Sacramento Mun.

Util. Dist., 616 F.3d at 528 (citation omitted), we hold that the 

Surplus Orders meet the requirements of § 824d. 

A

The virtual marketers argue that FERC violated 

§ 824d(a)’s requirement of “just and reasonable” rates because 

the surplus allocation system the Commission selected runs 

afoul of the “cost-causation principle.” That principle requires 

that “all approved rates reflect to some degree the costs 

actually caused by the customer who must pay them.” E. Ky.

Power Coop., Inc. v. FERC, 489 F.3d 1299, 1303 (D.C. Cir. 

2007) (internal quotation marks omitted). The cost-causation 

principle has its roots in monopoly rate regulation, where rates 

are required to “be based on the costs of providing service . . .

plus a just and fair return on equity.” Ala. Elec. Coop. v. FERC, 

684 F.2d 20, 27 (D.C. Cir. 1982). In the context of monopoly 

regulation, this principle helps ensure that utilities “produce 

revenues from each class of customers which match, as closely 

as practicable, the costs to serve each class or individual 

customer.” K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300-01 

(D.C. Cir. 1992) (internal quotation marks omitted) (emphasis 

omitted). That is, we scrutinize a utility’s rates to ensure a 
12

match between cost-causation and cost-responsibility. In the 

context of a market, we do the same, and our object of scrutiny 

is the operator’s method of fixing a market price, coupled with 

its system for disbursing any surpluses accumulated because of 

the LMP method. See Sithe/Independence Power Partners, 

L.P., 285 F.3d at 4-5 (holding that both aspects of the tariff are 

subject to review).

Indeed, we have analyzed other market operators’ surplus 

allocation schemes for compliance with the cost-causation 

principle. See id.; Sacramento Mun. Util. Dist., 616 F.3d at 

534-35. In Sithe, we held that FERC had failed to justify the 

imposition of marginal loss pricing under that principle, but we 

left the door open to clarification and explanation. See 285 F.3d 

at 4-5. That explanation was forthcoming in Sacramento 

Municipal Utility District (Sacramento). And though the 

Sacramento court upheld a pro rata surplus allocation system, 

616 F.3d at 535, whereas we are asked to review a system in 

which the petitioners receive no share, the Sacramento court’s 

reasoning still guides us here. Indeed, the reasoning offered in 

that case demonstrates why the virtual marketers’ 

cost-causation challenge fails.

In Sacramento, the California Independent System 

Operator proposed to distribute its transmission loss surplus 

“to transmission customers on a pro rata basis by using those 

revenues to uniformly reduce the cost of each megawatt-hour 

purchased on the system.” Id. at 534 (citation omitted). In 

concluding that this system complied with cost-causation 

principles, the Sacramento court observed that it is impossible 

to tease out causal responsibility for transmission losses in an 

LMP-based market system at any given point in time. Who is 

“causing” the first increment of current to flow through the 

system? Who is “causing” the marginal increment to flow? 

Since it is impossible to identify a “first” or a “marginal” 
13

increment, it is impossible to say who is causing which to flow. 

As the Sacramento court held, “it is not possible to determine a 

cost below marginal cost that any individual [customer] caused 

as a result of that customer’s [demand for] electricity.” Id. at 

534 (internal quotation marks omitted). Or, as we explained in 

a similar context, “for purposes of marginal cost pricing, all 

customers cause the incurrence of the costs associated with 

coincident peak load, whether by adding or merely continuing 

their usage.” Nat’l Ass’n of Regulatory Util. Comm’rs v. 

FERC, 475 F.3d 1277, 1285 (D.C. Cir. 2007) (citing Town of 

Norwood, Mass. v. FERC, 962 F.2d 20, 24 n.1 (D.C. Cir.

1992)). This means that any individual market participant 

deserves no share of the surplus under cost-causation, as each 

is equally the customer who “caused” the marginal 

transmission loss. See Sacramento Mun. Util. Dist., 616 F.3d at 

535 (“No customer is less deserving than another of being 

treated as the marginal customer . . . .”). Because FERC is 

treating the virtual marketers in this case “as the marginal 

customer,” they are being treated consistently with 

cost-causation principles.

The virtual marketers argue against the application of 

Sacramento’s view of cost causation in this case. They explain 

that they should not be treated “as the marginal customer” 

because, as they put it, “[v]irtual transactions by definition are 

purely financial and do not cause the physical flow of power 

over transmission lines.” Pet’rs’ Br. 30. It is true that the virtual 

marketers “submit bids for purely financial purchases or sales 

of energy, which do not entail physical generation or 

consumption of energy.” New York Indep. Sys. Operator, Inc., 

98 FERC ¶ 61,282, 62,216 (2002). But if physical activity were 

the measure of cost causation, then PJM would not be allowed 

to charge the virtual marketers at all, since they do not place 

real demands on the transmission system. 
14

Of course, this would be preposterous. The virtual 

marketers buy and sell contracts for electricity like all the other 

market participants. Even though their trades are purely 

financial, they depend on the existence of a market for actual 

electricity. And their activities, though “virtual,” contribute to 

the fluctuation of the market price, which in turn influences 

whether load-serving entities (the technical name for market 

participants who actually traffic in electricity) will purchase 

electricity at a given time. Just as a wheat-trading arbitrageur 

must trade wheat at the market price even though she does not 

take delivery of the wheat, an electricity-trading arbitrageur 

must trade electricity at the locational marginal price even 

though she, in some sense, does not “cause the physical flow of 

power over transmission lines.” Their trades must be treated as 

if they impose costs on the system just like the trades of all 

other participants. Sacramento established the principle that 

each customer who pays a locational marginal price is equally 

deserving of treatment as the marginal customer. Thus, each 

customer is entitled to no set share of the resulting surplus. Just 

as this principle applied to the transmission customers 

petitioning for review in Sacramento, 616 F.3d at 534-35, it 

applies to the virtual marketers in this case. 

It must be noted that the petitioners in Sacramento were 

dissatisfied with a pro rata share of the surplus, whereas the 

petitioners here are dissatisfied with a zero share.5 This puts 

this case on different footing from Sacramento in some crucial 

respects, requiring careful analysis of whether the surplus 

allocation system unduly discriminates against the virtual 

marketers.

 5 Again, we note that the virtual marketers did not always 

receive a zero share. See discussion infra note 6 and accompanying 

text.
15

B

There is no question that the surplus allocation system 

selected by FERC discriminates against virtual marketers. 

They receive none of the surplus, while the entities that pay the 

fixed costs of the grid receive significant disbursements even 

though, as a matter of cost causation, they do not deserve any 

particular amount of surplus, either. The virtual marketers 

argue that this discrimination is undue, in violation of 

§ 824d(b). They also argue that FERC lacked substantial 

evidence to back up its supposed justifications for approving

the discriminatory system, and that those justifications were 

arbitrary and capricious.

We accept disparate treatment between ratepayers only if 

FERC “offer[s] a valid reason for the disparity.” Electricity 

Consumers Resource Council v. FERC, 747 F.2d 1511, 1515

(D.C. Cir. 1984) (per curiam) (internal quotation marks 

omitted); see also Ark. Elec. Energy Consumers v. FERC, 290 

F.3d 362, 367 (D.C. Cir. 2002) (“A rate is not unduly 

preferential or unreasonably discriminatory if the utility can 

justify the disparate effect.” (internal quotation marks 

omitted)). FERC identifies valid reasons by pointing to 

differences between parties that are relevant to the 

achievement of permissible policy goals. See Transmission 

Agency of N. Cal. v. FERC, 628 F.3d 538, 549 (D.C. Cir. 2010) 

(“The court will not find a Commission determination to be 

unduly discriminatory if the entity claiming discrimination is 

not similarly situated to others.” (citation omitted)). In this 

case, the Surplus Orders sufficiently justified the approval of a

discriminatory system on the grounds that virtual marketers 

perform different roles from load-serving entities within the 

market, and that the system will limit virtual marketers’ 

incentives to engage in market manipulation. Therefore, we 
16

hold that the Commission’s action did not run afoul of 

§ 824d(b) or the APA.

FERC reasonably determined that the virtual marketers 

are not similarly situated to the rest of PJM’s market 

participants. The virtual marketers are distinguishable from 

other market participants because “unlike load[-serving 

entities], arbitrageurs balance each purchase transaction with a 

sales transaction.” Black Oak Energy, LLC, 125 FERC 

¶ 61,042, 61,145-46. That is, unlike entities that traffic in 

electricity, the virtual marketers have a purely financial interest 

in the markets. See Black Oak Energy, LLC, 122 FERC 

¶ 61,208, 62,185. They do not participate as producers or 

distributors of electricity, but rather as speculators and

risk-takers. Thus, they play a very different role within the 

system than do load-serving entities. From FERC’s policy 

perspective, the virtual marketers serve a useful purpose: they 

spot and exploit inefficiencies, driving prices closer to an 

accurate reflection of fundamental value. See, e.g., Black Oak 

Energy, LLC, 125 FERC ¶ 61,042, 61,146 (stating that the 

virtual marketers should “make transactions that reduce price 

divergence between the Day-Ahead and Real-Time markets”).

This sets them apart from load-serving entities, and FERC 

reasonably acts on this difference when it sets policy. 

But their unique position within the marketplace animates

FERC’s concern over whether virtual marketers will have a 

beneficial effect on the functioning of the markets. Since their 

business interests are purely speculative, FERC explained, the 

virtual marketers pose a threat as potential market 

manipulators. FERC reasonably approved the surplus 

allocation system because it promoted a policy of preventing 

market manipulation of a certain stripe. We defer to FERC’s 

policy priorities, so this explanation is adequate under arbitrary 

and capricious review. See Alcoa Inc. v. FERC, 564 F.3d 1342, 
17

1347 (D.C. Cir. 2009) (“Issues of rate design are fairly 

technical and, insofar as they are not technical, involve policy 

judgments that lie at the core of the regulatory mission.” 

(internal quotation marks and citations omitted)). As FERC 

explained, any formula that disburses surplus to the virtual 

marketers according to trading volume will create incentives 

for them to focus on increasing their surplus disbursements by 

increasing their trading volume. See Black Oak Energy, LLC,

122 FERC ¶ 61,208, 62,185. FERC put it this way: 

Paying excess loss charges to [virtual marketers] . . . is 

inconsistent with the concept of arbitrage itself. The 

benefits of arbitrage are supposed to result from trading 

acumen in being able to spot divergences between markets 

. . . . If [virtual marketers] can profit from the volume of 

their trades, they are not reacting only to perceived price 

differentials in LMP or congestion, and may make trades 

that would not be profitable based solely on price 

differentials alone. 

Id.; see also Black Oak Energy, LLC, 125 FERC ¶ 61,042, 

61,145 n.46 (“[U]sing a pure load ratio share calculation would 

provide an incentive for the arbitrageurs to conduct trades 

simply to receive a larger [surplus allocation].”). That 

increased trading could distort prices and destabilize the 

electricity markets, and such activity would place the virtual 

marketers far afield of their intended role within a competitive

energy system. FERC is well within its powers when it 

promotes a policy of limiting market participants’ incentives to 

speculate to the detriment of the efficient functioning of the 

market.

The virtual marketers argue that FERC lacks substantial 

evidence in the record to support its view that the system it 

selected will help prevent market manipulation. True, FERC’s 
18

analysis is not based on retrospective data. But given the 

circumstances, there is no way that it could be, because PJM 

had not implemented the proposed system when FERC had to 

act, and we defer to reasonable and cogent explanations of 

predictable economic outcomes, even in the absence of 

retrospective data. See FCC v. WNCN Listeners Guild, 450 

U.S. 582, 594-95 (1981) (approving of the FCC’s predictions 

about the effects of market forces). FERC’s economic 

reasoning also finds support in the submissions of PJM itself. 

See Black Oak Energy, LLC, 122 FERC ¶ 61,208, 62,180. 

These comments corroborate FERC’s reasonable economic 

predictions. 

In response, the virtual marketers present a parade of

horribles. They predict that the surplus allocation system will 

deter virtual marketers from participating in the PJM markets, 

“repress [efficient] price signals” to load-serving entities, and 

generally reduce the efficiency of the PJM market. See Pet’rs’ 

Br. 31, 33, 35. But none of these possibilities – and as far as we 

know, they are only possibilities – demonstrates the 

irrationality of FERC’s decisions. First of all, when raising the 

specter of decreased market participation by virtual traders, the 

petitioners fail to distinguish between good participation and 

bad participation. It is within FERC’s discretion to deter virtual 

marketers from making certain kinds of trades while leaving in 

place the background incentives to engage in 

efficiency-promoting arbitrage. Regarding the repression of 

efficient price signals to the load-serving entities and the 

supposed threats to the efficiency of the market, the virtual 

marketers point to no evidence supporting their view. FERC 

sufficiently explained why the system it chose was, in the 

Commission’s view, conducive to the production of efficient 

price signals. See Black Oak Energy, LLC, 122 FERC 

¶ 61,208, 62,184-86. At the very least, FERC determined that 

the surplus allocation system was better than available 
19

alternatives at fostering an efficient marketplace. Id. The 

arbitrary and capricious standard is a deferential one, and the 

virtual marketers’ speculative claims are not sufficient to 

overcome FERC’s explanation.

III

As discussed above, PJM’s surplus disbursement system 

ties distributions to the payment of the fixed costs of the grid. 

Though the virtual marketers pay none of those costs now, they 

once did when they traded on a market called the Up-To 

Congestion Market. 6 Even so, the virtual marketers now

receive no share of the surplus. Eventually, they filed a petition 

with FERC objecting to their disparate treatment, and in 

September 2009, the Commission ordered PJM to refund the 

virtual marketers for the surplus allocations to which they were 

entitled, amounting to $37 million. Black Oak Energy, LLC v. 

PJM Interconnection, LLC, 128 FERC ¶ 61,262, 62,222 

(2009).

But in July 2011, FERC took another look at the matter of 

refunds and changed its view, effectively ordering PJM to 

 6 The Up-To Congestion Market allows traders to specify a cap 

on the price they are willing to pay for the congestion component of 

an LMP price between two points on the grid. See Issue Details: 

Up-To Congestion Transactions, www.PJM.com (last visited July 

25, 2013), http://www.pjm.com/committees-and-groups/issue-track

ing/issue-tracking-details.aspx?Issue={A1D2CD14-012A-47E0-84

56-A76BDB97BA6C}. Until September 17, 2010, whenever virtual 

marketers made trades on the Up-To Congestion Market, they 

acquired “transmission reservations,” which included a component 

that paid for the fixed costs of the grid; since September 17, 2010, 

Up-To Congestion trades have not involved payment of grid fixed 

costs. See Pet’rs’ Br. 16 n.9 (citing PJM Interconnection Inc., LLC, 

132 FERC ¶ 61,244 (2010)).
20

recoup the refunds it had paid the virtual marketers. See Black 

Oak Energy, LLC v. PJM Interconnection, LLC, 136 FERC 

¶ 61,040, 61,163-64 (2011). The virtual marketers objected, 

arguing that FERC failed to provide proper notice that it might 

reconsider the decision to order refunds. In reply, FERC issued 

an order in May 2012 explaining that the virtual marketers 

should have been on notice and affirming its July 2011 

decision not to order refunds. See Black Oak Energy, LLC v. 

PJM Interconnection, LLC, 139 FERC ¶ 61,111, 61,780-82

(2012). 

The virtual marketers subject to the recoupment now seek 

review of the July 2011 and May 2012 orders.7 (Collectively, 

we call these the “Recoupment Orders.”) They argue that they 

lacked proper notice that their refunds might be recouped, and 

that the Recoupment Orders were, in any event, arbitrary, 

capricious, and contrary to the FPA’s prohibitions on unjust, 

unreasonable, and unduly discriminatory rates. We hold that 

FERC gave the virtual marketers reasonable notice that their 

refunds were under reconsideration, but that FERC’s orders 

were arbitrary and capricious because they were insufficiently 

justified.

A

FERC possesses sua sponte statutory authority to 

reconsider its orders under certain conditions:

Until the record in a proceeding shall have been filed in a 

court of appeals, . . . the Commission may at any time, 

upon reasonable notice and in such manner as it shall 

 7 This group includes those who brought the petition for review 

addressed in Parts I and II of this opinion, along with a group of 

similarly situated petitioner-intervenors.
21

deem proper, modify or set aside, in whole or in part, any 

finding or order made or issued by it under the provisions 

of this chapter.

16 U.S.C. § 825l(a). The virtual marketers argue that FERC 

lacked authority to change its course on the refunds because it 

gave them no “reasonable notice” that the issue was on the 

table. We give Chevron deference to FERC’s view of what 

constitutes “reasonable notice” even though it comes in this 

case not explicitly, as a statement of law, but implicitly, as a 

fact-bound determination. See INS v. Cardoza-Fonseca, 480 

U.S. 421, 447-48 (1987) (applying the Chevron framework to 

the “concrete meaning [given] through a process of 

case-by-case adjudication” to the statutory term “well-founded 

fear”); see also Nat’l R.R. Passenger Corp. v. Boston & Me. 

Corp., 503 U.S. 407, 420 (1992) (deferring to the ICC’s 

implicit interpretation of the statutory term “required” even 

though the ICC “did not in so many words articulate” it).

In its May 2012 order, FERC reasoned that the virtual 

marketers were put on notice that their refunds were at risk by 

two prior docket entries. First, a group of electricity exporters 

filed a request for rehearing of the September 2009 refund 

order arguing that FERC precedent barred retroactive 

alteration of the treatment of their surplus allocations. 8

Second, responding in April 2010 to that rehearing request and 

others, FERC filed an order that significantly expanded upon 

the scope of the exporters’ rehearing request. We need not 

decide whether the exporters’ rehearing request provided 

“reasonable notice” to the virtual marketers that their refunds 

were being reconsidered because the April 2010 order did.

 8 Electricity exporters conduct transactions that ship power 

from within the PJM system into neighboring systems. 
22

The April 2010 order responded to arguments raised in the 

exporters’ request for rehearing of the September 2009 order, 

and expanded beyond them. The exporters contended that 

retroactive alteration of the treatment of their surplus 

allocations was contrary to FERC precedent. Their arguments

were equally applicable to the virtual marketers’ refunds. As a 

non-profit, PJM lacks “corporate funds of its own to pay 

refunds, and it would have to acquire such funds either through 

surcharges or through an up-lift charge to all members.” Black 

Oak Energy, 136 FERC ¶ 61,040, 61,164 n.42. Thus, PJM’s 

membership must pay for any refund that FERC orders PJM to 

pay. According to the exporters, members’ confidence in the 

marketplace was shaken by having to pay for the refunds. See 

Black Oak Energy, LLC, 139 FERC ¶ 61,111, 61,777, 

61,780-81. This logic applied to any surplus allocation refund 

made by PJM, and the April 2010 order expanded the scope of 

reconsideration to include all the refunds ordered in September 

2009. 

The broad inquiry FERC initiated in the April 2010 order 

should have made it clear to the virtual marketers that their 

refunds were subject to reconsideration. That order gave all 

parties “45 days from the date of PJM’s filing to brief any

issues with respect to refunds . . . .” See Black Oak Energy, 

LLC v. PJM Interconnection, LLC, 131 FERC ¶ 61,024, 

61,171-72 (2010) (emphasis added). In other words, the 

September 2009 refund order was not final. The April 2010 

order also directed PJM to submit a “detailed refund report,” 

which would identify all parties burdened or benefited by the 

refunds and would explain why PJM conducted the refund as it 

had. Id. (The report was designed to update and clarify a refund 

report that FERC required of PJM in September 2009. Id.) It is 

reasonable for FERC to hold that the scope of the April 2010 

order placed the virtual marketers on notice that their refunds 

might be reconsidered.
23

B

The virtual marketers argue that the Recoupment Orders 

are unjust, unreasonable, and unduly discriminatory because 

they “reinstitute” a tariff that FERC itself had found unlawful

in September 2009. Pet’rs’ Br. 46-47 (citing Black Oak 

Energy, LLC, 128 FERC ¶ 61,262, 62,221-22 (holding that 

PJM’s treatment of Up-To Congestion trades ran afoul of 

§ 824d)). But the Recoupment Orders did not “reinstitute” an 

unlawful tariff; they merely modified the remedy that FERC 

ordered in September 2009. That order imposed a prospective

remedy, banning PJM from mistreating virtual marketers who 

contribute to the fixed costs of the grid, and a retrospective 

remedy, effectively ordering PJM to pay refunds. With the 

revisions in the Recoupment Orders, PJM continues to be 

bound by the ban on mistreatment of virtual marketers who 

contribute to fixed costs. The revisions nullified only the 

retrospective feature of the September 2009 remedy; they did 

not reinstate an unjust tariff. Thus, the virtual marketers’ 

“unjust, unreasonable, and unduly discriminatory” argument 

fails.

But we agree with the virtual marketers that the

Commission acted arbitrarily and capriciously when it 

effectively ordered PJM to recoup the refunds. FERC justified

the recoupment on the ground that it brought the remedies for 

PJM’s unjust distribution of the surplus into alignment with 

Commission precedent. According to FERC, its policy is to 

deny refunds where revenues were accurately collected, and 

rates are being changed on a prospective basis. See Black Oak 

Energy, LLC, 136 FERC ¶ 61,040, 61,163-64 (citing orders). 

FERC argued here that PJM had accurately collected revenues 

according to its LMP tariff, but that the system needed to be 

altered. By this reasoning, had FERC followed its precedent in 
24

the first instance, there would have been no $37 million refund.

FERC would have required PJM to comply prospectively and 

left it at that. The Recoupment Orders were FERC’s effort at 

correcting this mistake. FERC admits that it “belatedly” 

reached its conclusion that no refund should have been ordered

in the first place, thus “compelling PJM to recoup refunds it 

previously made,” but argues that when it reached this correct 

conclusion “is not of legal consequence.” Resp’ts Br. 41 

(citation omitted). We disagree.

There is a significant distinction between denying refunds 

and recouping them. As the virtual marketers argued in their 

request for rehearing of the July 2011 order, recoupment may 

reduce the confidence of participants in the smooth functioning 

of the market in a way that straightforward denial of refunds 

does not. Yet, in its Recoupment Orders, FERC repeatedly 

obscured the fact that it was effectively ordering PJM to claw 

back money that has already been paid out. Instead of 

justifying recoupment, the Commission wrote as if it were 

denying the refunds outright. The order stated, “denying 

refunds . . . is the fairest approach,” and “refunds should not be 

required.” Black Oak Energy, LLC, 139 FERC ¶ 61,111,

61,782-83. True enough, but there is more to this case than 

that, for the refunds at issue were already out the door. In 

addition to explaining why it should have denied the refunds in 

the first place, FERC must explain why recouping is 

warranted. Because FERC failed to explain how it analyzed 

this crucial aspect of the case, we hold that the Commission 

acted arbitrarily and capriciously. See, e.g., Motor Vehicle 

Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43

(1983). It may well be that FERC’s policy reasons for

effectively ordering recoupment outweigh its negative effects,

but FERC must analyze that question, not ignore it. For that

reason, we remand.
25

Although we remand, we do so without vacating the 

Recoupment Orders. The decision to vacate depends on two 

factors: the likelihood that “deficiencies” in an order can be 

redressed on remand, even if the agency reaches the same 

result, and the “disruptive consequences” of vacatur.

Allied-Signal v. Nuclear Regulatory Comm’n, 988 F.2d 146, 

150-51 (D.C. Cir. 1993). We find it plausible that FERC can 

redress its failure of explanation on remand while reaching the 

same result. See, e.g., Lone Mountain Processing, Inc. v. Sec’y 

of Labor, 709 F.3d 1161, 1164 (D.C. Cir. 2013) (“The 

Commission may well arrive at the same result it reached 

originally, but it must do so with more clarity than it showed in 

the first instance.” (citation omitted)). And vacatur in this case

would certainly be disruptive because it would prompt yet 

another refund, which would require yet another charge on

uninvolved market participants. As we have noted, because

PJM is a non-profit, the only way it can obtain funds to pay out 

a refund is by charging its market participants to cover them. 

See Black Oak Energy, LLC, 139 FERC ¶ 61,111, 61,783. If 

FERC, considering all the factors, ultimately concludes that 

recoupment was the proper path, the whole cycle would repeat 

itself, imposing significant transaction costs on PJM, its 

members, and the virtual marketers themselves. Faced with 

those prospects, we deem it better to preserve the status quo as 

FERC reconsiders its Recoupment Orders. However, we 

emphasize that FERC’s opportunity to reconsider is not an 

invitation to do nothing. See In re Core Commc’ns, Inc., 531 

F.3d 849, 862 (D.C. Cir. 2008) (Griffith, J., concurring). The 

Commission may not obtain the result it seeks through inaction 

when it has failed to justify that result with reasoning. 

IV

For the foregoing reasons, we deny the petition for review 

of the Surplus Orders and grant the petition for review of the 
26

Recoupment Orders. We remand the matter of the recoupment

to the Commission for reconsideration consistent with this 

opinion.

So ordered.