Black Oak Energy, LLC v. Federal Energy Regulatory Commission , 725 F.3d 230 ( 2013 )


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  •  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.
    

Document Info

Docket Number: 08-1386, 11-1275, 12-1286

Citation Numbers: 406 U.S. App. D.C. 357, 725 F.3d 230, 2013 U.S. App. LEXIS 16201, 2013 WL 3988709

Judges: Garland, Rogers, Griffith

Filed Date: 8/6/2013

Precedential Status: Precedential

Modified Date: 10/19/2024

Authorities (18)

Immigration & Naturalization Service v. Cardoza-Fonseca , 107 S. Ct. 1207 ( 1987 )

allied-signal-inc-v-us-nuclear-regulatory-commission-and-the-united , 988 F.2d 146 ( 1993 )

Federal Communications Commission v. WNCN Listeners Guild , 101 S. Ct. 1266 ( 1981 )

Arkansas Electric Energy Consumers v. Federal Energy ... , 290 F.3d 362 ( 2002 )

In Re Core Communications, Inc. , 531 F.3d 849 ( 2008 )

Motor Vehicle Mfrs. Assn. of United States, Inc. v. State ... , 103 S. Ct. 2856 ( 1983 )

Alcoa Inc. v. Federal Energy Regulatory Commission , 564 F.3d 1342 ( 2009 )

Western Area Power Administration v. Federal Energy ... , 525 F.3d 40 ( 2008 )

Wisconsin Public Power Inc. v. Federal Energy Regulatory ... , 493 F.3d 239 ( 2007 )

Edison Mission Energy, Inc. v. Federal Energy Regulatory ... , 394 F.3d 964 ( 2005 )

E KY Power Coop v. FERC , 489 F.3d 1299 ( 2007 )

K N Energy, Inc. v. Federal Energy Regulatory Commission, ... , 968 F.2d 1295 ( 1992 )

Sithe/Independence Power Partners, L.P. v. Federal Energy ... , 285 F.3d 1 ( 2002 )

Midwest Iso Transmission Owners v. Federal Energy ... , 373 F.3d 1361 ( 2004 )

National Association of Regulatory Utility Commissioners v. ... , 475 F.3d 1277 ( 2007 )

electricity-consumers-resource-council-v-federal-energy-regulatory , 747 F.2d 1511 ( 1984 )

Sacramento Municipal Utility District v. Federal Energy ... , 616 F.3d 520 ( 2010 )

National Railroad Passenger Corporation v. Boston & Maine ... , 112 S. Ct. 1394 ( 1992 )

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