AMEREN SERVICES COMPANY, et al., Petitioners v. FEDERAL ENERGY REGULATORY COMMISSION, Respondent American Wind Energy Association, et al., Intervenors
When new sources of power generation connect to the existing transmission grid, the grid often requires new construction beyond the point of interconnection in order to accommodate the increased flows of electricity. FERC issued a series of orders empowering incoming generators within the Midcontinent Independent System Operator (MISO) region 1 to elect to self-fund this new construction, or to seek financing from third parties, regardless of whether the current grid owners wish to fund the construction themselves.
The Commission justified the orders on two grounds. First, it found that allowing transmission owners to choose between funding options—and thus, potentially, to impose subsequent charges to generators via transmission owner funding—could allow the transmission owners to discriminate among generators. Secondly, it held that the charges to generators would be (or could be) unjust and unreasonable under the Federal Power Act. Petitioning transmission owners challenge both grounds. We conclude that Petitioners are correct regarding the discrimination point: there is neither evidence nor economic logic supporting FERC's discriminatory theory as applied to transmission owners without affiliated generation assets.
FERC's second ground raises a unique and important conceptual issue. Petitioners argue that involuntary generator funding compels them to construct, own, and operate facilities without compensatory network upgrade charges—thus forcing them to accept additional risk without corresponding return as essentially non-profit managers of these upgrade facilities. We do not think that FERC adequately responded to this argument. We therefore remand the case to the Commission.
We have previously explained the series of steps FERC took to unbundle the electric power system, enabling and encouraging new independent generators to create a competitive market for power generation.2 Transmission owners, which had previously served their own vertically integrated sources of power generation, were obliged to accept power from any source on a non-discriminatory basis.
For independent generators to utilize the grid, they must first connect to it. FERC thus used its rulemaking powers to issue Order No. 2003, which standardized the procedures for generator interconnection and directed each transmission network to maintain a pro forma generator interconnection agreement.3 Order No. 2003 also established the “at or beyond” rule, which distinguished between two types of new construction necessary to connect new generation sources into the grid. See Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277, 1284–86 (D.C. Cir. 2007). The first category, called “interconnection facilities,” includes those facilities and equipment that lie between the generation source and the point of interconnection with the transmission network. Under the “at or beyond” rule, the cost of interconnection facilities are the sole responsibility of the incoming generator. That allocation of costs is undisputed in this proceeding. And Petitioners do not own or manage those “interconnection facilities.” The second category includes those additional facilities and equipment that are needed beyond the “point of interconnection”—in other words, any new construction that occurs within Petitioners' transmission grid itself to accommodate the incoming flows of new power. This latter category of construction, called “network upgrades,” is the focus of the present dispute.
* * *
As we have also explained, FERC encouraged the creation of Regional Transmission Organizations (RTOs) to integrate the fragmented transmission grid on a regional basis, along with Independent System Operators (ISOs) as non-profit entities which would control access to the grid within their respective regions. Wisconsin Public Power, Inc., 493 F.3d at 247. In Order No. 2003, the Commission set a default rule that transmission owners would bear responsibility for the network upgrades, but gave ISOs “flexibility to customize its interconnection procedures and agreements to meet regional needs.” Order No. 2003 at P 827; id. at P 676. In this case, we encounter MISO, which qualifies as both an RTO and an ISO.
Originally, MISO had allocated the costs equally between the incoming generator and the transmission owner. As such, under transmission owner funding—which it could choose—the transmission owner would initially provide the capital for construction, but would recover 50 percent of that capital (a “return of” capital), along with an appropriate return on that capital, through network upgrade charges. It would fund the other 50 percent of the costs by passing them on to all of its customers through its rates—again, including an appropriate rate of return. Under generator funding, the generator would initially provide the capital for construction, and would receive 50 percent of that capital from the transmission owner through credits for transmission service. E.ON at P 3.
But a problem arose: this 50/50 arrangement placed most of the cost burden on the pricing zone where interconnection occurred, but the power from the new generation sources often exceeded the load within those local zones in which they connected. Midwest Independent Transmission System Operator, Inc., 129 FERC ¶ 61,060, at P 7 (2009) (“MISO Tariff Amendment”). As a result, the local customers of the transmission owner bore a disproportionate share of the cost burden of upgrades that supported power that would ultimately benefit more remote customers throughout the MISO region. Id. at P 11. Rather than forcing their local customers to shoulder this regional burden, several local transmission owners threatened to withdraw from MISO if the cost allocation remained unchanged. Id. at P 10.
To remedy this problem, MISO proposed (and FERC approved) a new allocation of capital costs: for network upgrades rated at 345 kilovolts or above, the interconnecting generator bears 90 percent of those costs, and transmission owners (and their local customers) bear 10 percent. In other words, the 10 percent would be included in the transmission owner's rate base. For projects rated below 345 kilovolts, the interconnecting generator bears 100 percent of the costs. This reallocation was intended to comport with FERC's “principle that network upgrades should be paid for by the parties that cause and benefit from such upgrades.” MISO Tariff Amendment at P 3.
The manner in which the incoming generator and transmission owner actually pay these capital costs depends upon the way the network upgrades are funded. Originally, the MISO tariff contained three options for providing the capital required to construct the network upgrades. We need not discuss the first because it was removed by the Commission in its E.ON decision.4
Under the second alternative, Option 2 or “generator funding,” the interconnecting generator would provide the funding for the network upgrades prior to construction. The transmission owner would not refund this capital to the interconnecting generator, and would neither include the capital in its rate base nor charge the interconnecting generator a return on that capital.5 In short, generator funding means the owner of the transmission grid neither pays for, nor earns a return upon, the new construction that takes place within its network.
Under the third alternative, “transmission owner funding,” the transmission owner pays for the construction of the upgrades to its network and then recovers the incoming generator's portion of the cost burden over time through periodic network upgrade charges that include a return on the capital investment. These network upgrade charges are paid from the incoming generator to the transmission owner over the duration of the agreement. Importantly, they include both a return of capital, which is the 90 percent cost reimbursement paid over time as the network upgrades depreciate, and a return on capital. They are thus economically equivalent to inclusion in the rate base, with the exception that they are charged specifically to the incoming generator rather than to all of the transmission owner's customers. Any portion of the upgrade costs that remains to be borne by the transmission owner is then passed on to all of its customers through its rates.
Following the Commission's E.ON decision, then, it was clear that the transmission owner could choose between two options—generator funding or transmission owner funding—to finance construction of network upgrades when an incoming generator sought to directly interconnect with its network.
To further complicate the matter, however, the addition of new generation sources can cause second-order effects across the grid. Sometimes, in order to support flows of power from a new source, network upgrades must be made by transmission owners that do not connect directly to the incoming generator. And in other instances, the coincidence of multiple interconnection requests can create a need for a set of common network upgrades, which enable the grid to support the several incoming generators. In these two situations, MISO's tariff did not initially permit transmission owners to choose between funding options.
It was that disparity between the treatment of direct and indirect network upgrades which gave rise to this case. In 2014, when faced with the prospect of building network upgrades to support an indirectly connected incoming generator, a transmission owner named Otter Tail requested that MISO offer it the same choice (between generator funding and transmission owner funding) enjoyed by directly connected transmission owners. MISO consented, and submitted an agreement to FERC that would allow Otter Tail to elect transmission owner funding.6 The incoming generator objected to this request, preferring instead to utilize generator funding for the network upgrades that would be needed to support its power.
Otter Tail also filed a complaint under Sections 206 and 306 of the Federal Power Act. It contended that the disparity between directly connected transmission owners (who could choose to fund the upgrades to their networks) and indirectly connected transmission owners (who could not choose transmission owner funding) rendered MISO's tariff unjust and unreasonable. Otter Tail requested that FERC order MISO to bring all transmission owners into alignment by modifying its tariff to allow the choice of transmission owner funding for indirect interconnections.
The Commission agreed with Otter Tail that this disparity was unsupportable. In its June 2015 Order,7 the first of the orders under review in this case, it found that because “the funding and construction obligations are equal whether the connection of a new generator is direct or indirect ․ the same funding options should be available to all interconnection customers in MISO.” June 2015 Order at P 47. Ironically, it cured the disparity not by providing the choice of transmission owner funding to indirectly connected owners—but instead by removing that choice from those with direct connections. Otter Tail was hoist on its own petard.
The Commission determined that providing directly connected transmission owners with the ability to select transmission owner funding “may be unjust, unreasonable, unduly discriminatory or preferential because it ․ may result in discriminatory treatment by the transmission owner of different interconnection customers.”8 June 2015 Order at P 48 (emphasis added). This discriminatory treatment, according to FERC, stemmed from the difference in costs borne by the generator under the two types of funding.
* * *
Those cost differences, according to the Commission, had two main causes. FERC thought that generators missed the opportunity to seek favorable construction funding in competitive capital markets; in other words, the use of transmission owner funding could prevent the generator from finding a better deal from a third party. June 2015 Order at P 48. Second, FERC contended that transmission owner funding imposed a more onerous “security” requirement on generators. June 2015 Order at P 49 & n.110. Transmission owners required generators to provide some form of financial assurance—such as a guarantee, surety bond, or letter of credit—that was sufficient to cover the cost commitments undertaken by the transmission owner in constructing the network upgrades. Under generator funding, this requirement lasted only for the duration of construction. But under transmission owner funding, security was required for the duration of the funding agreement. As an example, one proposed transmission owner funding agreement specified that an incoming generator would maintain a letter of credit over a term of 20 years. December 2015 Order at P 33 & n.60.
Given these tentative findings, FERC instituted a formal adjudicatory proceeding under Section 206 of the Federal Power Act, requiring MISO to either modify its tariff to require generator consent for transmission owner funding, or to explain why the Commission's views were not correct. This proceeding attracted a large cohort of intervenors; various transmission owners (including Petitioners), independent generators, and associations that represent those groups each contributed comments before the Commission. In the second of the orders under review in this case (“December 2015 Order”), FERC affirmed its earlier finding that “it is potentially unjust, unreasonable and unduly discriminatory to deprive the interconnection customer of the ability to provide its own capital funding.” This petition for review followed.9
The Commission's position before us largely tracks its final decision below. It relied, as we noted, on two grounds to determine that transmission owners may not insist on transmission owner funding, but that generators must instead have the option to self-fund. The first is that giving transmission owners the option to fund the upgrades provides them with the power to discriminate amongst generators who wish to connect to the grid. (Discrimination is, of course, prohibited by the Federal Power Act. See 16 U.S.C. §§ 824d(b); 824e(a).) Petitioners argue vigorously, however, that there is neither evidence of discrimination 10 nor any economic incentive on the part of transmission owners to discriminate. To be sure, if the transmission owners still owned integrated generation facilities, that would present a competitive motive. But in emphasizing Order No. 888 and the Supreme Court's decision in New York v. FERC, 535 U.S. 1 (2002), the dissent harks back to a time we once described as “the bad old days,” when transmission companies also owned generation facilities and operated as vertically integrated monopolies. Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1363 (2004); cf. Dissent at 10–11. This is fighting a battle that has already been won. Here, only one of the petitioning transmission owners—in Missouri—still owns a generator; none of the rest do. And FERC did not pay any attention to that small exception among Petitioners; it did not limit its order to that generator. Moreover, as we know from our other cases, the broader trend following Orders No. 888 and 2000 has been toward divestiture by transmission owners of generation assets.11 Granted, FERC is not obliged to show actual evidence to support a determination of potential discrimination, but in the absence of evidence, the Commission must at least rest on economic theory and logic. We agree with Petitioners; that is lacking here.
Our dissenting colleague suggests that we actually lack jurisdiction to consider Petitioners' anti-discrimination argument—at least insofar as Petitioners point out that only a transmission owner which also owns a generator would have an incentive to discriminate—because Petitioners did not explicitly make that specific point to the Commission. But when Petitioners vigorously contended there was no evidence to support a finding of discrimination and no reason to “predict[ ]” it would occur as “a foregone conclusion,” Request for Rehearing of the Indicated Transmission Owners, Docket Nos. EL15-68, EL15-36 (FERC January 28, 2016) at 23 n.59, it can hardly be thought a new argument to suggest what might constitute evidence of potential discrimination, if it were to exist.
The second theory upon which FERC based its orders was that allowing transmission owners to insist on transmission owner funding would be “unjust and unreasonable” under the Federal Power Act because it imposed increased costs without any corresponding increase in service. We should note at the outset that the Commission does not assert that transmission owner funding is inherently unjust and unreasonable; it is only if the transmission owner chooses that method of funding that FERC believes it crosses the unjust and unreasonable line. (That suggests that FERC is really seeking to enhance the generator's bargaining position vis-a-vis the transmission owners—which, of course, is why generators have intervened in support of the Commission.) As we explained, FERC wants generators to have the option to seek the funding for the new construction from parties other than the transmission owners because it asserts that cheaper funding may be available elsewhere. FERC observes that the transmission owners have an incentive to increase costs because such costs will either be included in the rate base—upon which revenue can be predicated—or in charges back to the generator owner, which also include a measure of profit. FERC also states that the transmission owners have no right to the generator's financing business.
The Commission contends moreover that generator funding avoids the larger security costs under transmission owner funding. We are puzzled by FERC's reasoning on this point, because if the generator had found another source of capital to cover the costs of the upgrade, we can't imagine that the generator wouldn't have to provide the same kind of security to that third party—covering the risk of default—that it does for transmission owners.12 Still, it is certainly possible, if not probable, that a generator could find an alternative source of capital (including any necessary security) that would be cheaper than that provided by the transmission owner. Indeed, as the dissent notes, the Commission states a simple economic truth in recognizing that the generators “have an incentive to find lowest cost funding solutions, while transmission owners do not.” Dissent at 6.
But this proposition applies equally to all cost components of Network Upgrade construction, which Petitioners perform on the generators' behalf—not merely its funding. By the same logic, since they bear a greater share of cost responsibility, the generators also have a sharper incentive than Petitioners to reduce the costs of raw materials, or construction labor, or design fees. This is why the generators can challenge inclusion of any such costs that deviate unreasonably from a fair market price before the Commission.
In any event, it does not necessarily follow from any incentive differences that FERC may compel transmission owners to operate the upgrades without an opportunity to earn a return. Such a determination would require reasoned justification by the Commission, and consideration of any appropriately raised concerns by the parties. And Petitioners do in fact raise two rather powerful arguments against FERC's “unjust and unreasonable” theory.
First, they claim that under compelled generator funding, transmission owners will be forced to assume certain costs that are never compensated. Keeping in mind that the transmission owners will own and operate the grid, including the upgrades, they will bear liability for insurance deductibles and all sorts of litigation, including environmental and reliability claims (such as blackout risks). The Commission's response dismisses these risks; it asserts that upgrades might actually reduce congestion risks, see August 2016 Order Denying Rehearing at P 17, but it makes no real attempt to holistically assess all of the various risks and benefits to the transmission owner caused by the addition of the upgrade facilities.
Instead, FERC asserts that because “this case concerns only the capital costs of facility construction,” Resp.Br. 35, and since “[t]ransmission owners will recover their cost of service (beyond capital costs) through their transmission rates,” id. (quoting December 2015 Rehearing Order P 57), the petitioning transmission owners have no justifiable complaint.13 But in this adjudication, FERC never acknowledged that these separate risks and consequent expenses even exist—they are thought to be somehow “baked in” to the existing compensation structure. See August 2016 Order Denying Rehearing at P 13. If Petitioners are correct that they face increased risk without compensation, that would be relevant and could certainly undermine FERC's conclusion.
Contrary to the dissent's characterization, FERC's musing that network upgrades might actually reduce reliability risk is hardly a “finding” of fact to which we are obliged to defer. It is, at most, a possibility to be explored—and one that sounds a bit far fetched to us. In any event, FERC makes no assertion that any such reduction of reliability risk would be of sufficient magnitude that the added facilities would actually reduce the net overall risk borne by the owner-operator. Further, the dissent's suggestion that the environmental risks are identical regardless of who provides capital for the upgrades is something of a diversion. Of course that is true. The problem is that the risk is always borne by the transmission owner, and under Option 2, Petitioners contend they are not compensated for bearing it. And whether the transmission owner chooses, at its own expense, to insure that risk is obviously irrelevant. Cf. Dissent at 14.
We therefore think that FERC inadequately considered Petitioners' argument 14 that all costs, and risks, are not baked in—that, in fact, shareholders are forced to accept incremental exposure to loss with no corresponding benefit. Without analysis, the Commission casts doubt on the likelihood that these risks exist. But if Petitioners are conceptually correct that they bear these risks as owners of the transmission lines, it supports their basic contention that they are entitled to be compensated now as owners for operating the upgrades. And since this contention was raised appropriately, failure to meaningfully respond to it makes FERC's decision arbitrary and capricious. See PSEG Energy Res. & Trade LLC v. FERC, 665 F.3d 203, 208, 209–10 (D.C. Cir. 2011).
Petitioners' second—and more fundamental—argument is that FERC's orders require them to act, at least in part, as a nonprofit business. Put another way, by modifying the transmission owners' entire enterprise, FERC's orders attack their very business model and thereby create a risk that new capital investment will be deterred. In its orders, FERC distorted and dismissed this argument, stating derisively that because generators bear responsibility for most of the capital costs under generator funding, the entire enterprise argument “implies that the affected system operator is owed the interconnection customer's financing business.” June 2015 Order at P 50. FERC seems to believe that transmission owners are simply not entitled to participate in funding the network upgrades, and importantly to earn a return on capital.
But a careful reading of Supreme Court precedent reveals that a regulated industry is entitled to a return that is sufficient to ensure that new capital can be attracted. See Hope, 320 U.S. at 603. Therefore, as we have often said, a utility's return must allow it to compete for funding in the financial markets. See, e.g., Maine v. FERC, 854 F.3d 10, 20 (D.C. Cir. 2017). Investors, however, invest in entire enterprises, not just portions thereof. FERC must explain how investors could be expected to underwrite the prospect of potentially large non-profit appendages with no compensatory incremental return. It is certainly true, as the transmission owners note, that the answer FERC offered—to cajole consent from the generators 15 —is a non sequitur.
Our dissenting colleague responds to Petitioners' primary argument—that FERC's order requires them to operate partly as a non-profit business—by asserting that Hope does not guarantee that each portion of a regulated business will be profitable. Dissent at 15. That is, of course, true, but it seems undisputable that when portions of a business are unprofitable, it detracts from the attractiveness to investors of the business as a whole—and that is a concern that the Commission must at least address under Hope's capital-attraction standard.
This is to say nothing of the fact that added complexity can be expected to impose its own form of deterrence upon investors, via information costs. Even if FERC could somehow provide protection for each of the many risks involved, potential investors would need to expend costly time and resources to examine and understand what the petitioning transmission owners would call the “non-profit” segments of their business, in order to verify that they are, in fact, riskless. And investors' confidence in their own assessment of such risklessness would itself carry some perceived risk. To the extent that other comparable utilities do not carry responsibility for such “non-profit” lines of business, and earn the same rate of return on the assets in their rate base, they would thus become relatively more attractive to investment professionals.
Notwithstanding these concerns, the non-profit innovation might remain bearable so long as the generator-funded upgrades growing inside the grid remain tiny relative to their host. But if more and more of a transmission owner's business is to be owned and operated on a non-profit basis, these additions would likely deter investors and diminish the ability of the transmission grid to attract capital for future maintenance and expansion. That FERC's orders cross a rather significant conceptual line was revealed when FERC's counsel was asked whether, if a group of generators got together to fund a billion-dollar upgrade that totally refurbished a portion of the grid, the transmission owner would be obliged to operate and assume liability for the upgrade—with operations and maintenance costs reimbursed, but no return. The answer, alarmingly, was yes. Oral Arg. at 39:36; see also id. at 51:39–52:15. Transmission owners' desire to retain the choice to fund the upgrades is therefore much more than a claim of entitlement to the generator's “financing business.” It is, at root, a desire to retain control over their own business.
In its discussion of the balance of investor and consumer interests mandated by Hope, the Commission stresses that capital costs are ultimately borne by the generator under either option. But this backward-looking perspective elides Hope's forward-looking capital attraction standard. 320 U.S. at 605. The ex ante question of cost allocation is thus analytically distinct from the ex post question of responsibility for ownership and operation that we discussed above. FERC cannot sufficiently respond to the transmission owners' clearly stated concerns about the latter question by merely pointing to the outcome of the former.
In sum, petitioning transmission owners raise serious statutory and constitutional concerns with respect to the effect of compulsory generator-funded upgrades on their business model. They ask why their current investors should be forced to accept risk-bearing additions to their network with zero return. We think an even greater concern is whether any future providers of capital would choose to enter into that questionable bargain. See Hope, 320 U.S. at 603. At present, however, we have no need to reach the merits of those questions. Because the Commission failed even to respond to these concerns, and because it offered neither evidence of nor motive for discrimination by non-vertically integrated transmission owners among their customers, it is sufficient now to require that it do so. On remand, FERC should provide reasoned consideration of these arguments by explaining whether all risks are truly “baked in,” responding to the transmission owners' “entire enterprise” argument, and addressing the effect of these orders on the ability of transmission businesses to attract future capital.
Setting aside the merits of the case, FERC contends in the alternative that our review is premature because the transmission owners can seek to adjust their rates in a future hearing under Section 205 of the Federal Power Act. We are thus urged not to intervene on the transmission owners' behalf, because they can, and should, simply seek relief from FERC directly in a later hearing.
But for two reasons, a Section 205 hearing cannot provide the relief that the petitioning transmission owners seek. First, FERC's precedents do not provide compensation for several of the classes of risks that Petitioners allege will accompany construction and operation of the network upgrade facilities. For example, fines and penalties for violations of mandatory reliability standards and environmental regulations are generally charged directly to the utility, not passed through to customers via rate increases. See, e.g., In re SCANA Corp., 118 FERC ¶ 61,028 at P 1, 7–8. Further, FERC has stated that it takes a comprehensive view of a company, its employees, and its operations when wielding its enforcement power against the utilities it governs. See generally Enforcement of Statutes, Orders, Rules, and Regulations, 113 FERC ¶ 61,068 (2005). As such, compensation for the types of risks identified by the petitioning transmission owners may not be possible, even if proven in a future hearing.
The second reason why a Section 205 hearing would be of little use to the petitioning transmission owners is that FERC has spoken with utter and consistent clarity as to the question of whether a rate of return is justified under the generator funding option. See Resp.Br. 33; August 2016 Rehearing Order PP 12–20; December 2015 Rehearing Order PP 56–59. If, in a future Section 205 hearing, the transmission owners were to seek to include generator-funded assets in their rate base, a negative result is a foregone conclusion. The relevant question, then, is not whether the rate can be adjusted later in a Section 205 hearing—but instead whether a transmission owner can be forced to accept generator-funded upgrades in the first instance. That question is squarely before us; we return it to FERC for a more thorough answer.
On a related point, the dissent suggests that since the Commission plans to take up the issue of generic interconnection costs in a pending rulemaking, it is unnecessary for us to consider Petitioners' concern in this case. The dissent implies that FERC has consciously chosen a specific “manner of proceeding, addressing capital costs here and generic interconnection cost issues in a separate docket.” Dissent at 9.
The Commission did not make this argument before us, and for good reason: the purported plan to separate capital costs from other cost issues is fiction. (In fact, FERC's sole mention of its separate rulemaking in the proceedings below was to acknowledge and reject the Petitioners' request to avoid adjudication while the rulemaking was in progress. See December 2015 Order PP 40, 60.) In the referenced rulemaking—Docket No. RM15-21—FERC requested comments on Intervenor AWEA's proposals for changes to the standard interconnection agreements. See Notice of Petition for Rulemaking, Docket No. RM15-21 (FERC July 7, 2015). And those proposals explicitly include, in multiple locations, the precise issue of capital cost allocation.16 This is unsurprising; as explained at length above, the two issues are deeply intertwined.
Further, even assuming that FERC had intended such a “manner of proceeding” (and that such a dichotomy would be conceptually tenable), the dissent's wait-and-see suggestion confuses adjudication—which is retroactive, determining whether a party violated legal policy—with rulemaking, which is of only future effect. We once described an agency's effort to offer future rulemaking as a response to a claim of agency illegality as an “administrative law shell game,” Am. Tel. & Tel. Co. v. FCC, 978 F.2d 727, 732 (D.C. Cir. 1992), a phrase the Supreme Court thought apt. See MCI Telecomm. v. Am. Tel. & Tel. Co., 512 U.S. 218, 222 (1994).
When we remand orders to FERC, two factors inform our decision whether to vacate: the gravity of the orders' flaws, and the “disruptive consequences” that may result. Black Oak Energy, LLC v. FERC, 725 F.3d 230, 244 (D.C. Cir. 2013) (quoting Allied–Signal v. Nuclear Regulatory Comm'n, 988 F.2d 146, 150–51 (D.C. Cir. 1993) ).
As noted above, we have no need to finally decide the transmission owners' central complaint in this case: that under the Federal Power Act and the Constitution, FERC cannot force them to construct and operate generator-funded network upgrades.17 Indeed, we should not do so until the Commission has developed a record by considering that question itself. But we are troubled by the prospect of allowing the orders to continue in the interim.
The transmission owners complain that generator-funded upgrades draft them into service to manage non-profit appendages to their network; we today remand in part because FERC failed to respond to that argument. By approving changes to the MISO tariff, however, the August 2016 Order on Compliance opens the floodgates to involuntary generator-funded interconnection projects.18 And we must bear in mind that the Commission's June 2015 Order indicates that its logic in this case would apply to all indirect upgrades as well. FERC may determine on remand that a transmission owner's consent is required to impose generator-funded network upgrades, or that it would be unjust or unreasonable to force the transmission owners to accept increased risk with no increased return. If it does not, Article III courts may subsequently require it to do so. In that event, what will happen to the projects that have commenced in the interim? How will the generators, who under the Commission's logic will presumably have obtained funding from the capital markets, extricate themselves from those newly-invalid contracts? Will the financiers with whom they deal insert clauses imposing costly “break-up fees,” in anticipation of the ultimate resolution of this question? Or worse: will half-completed projects be left stranded because they were financially viable when generator-funded, but become unprofitable when they bear the full cost of the attendant risks under transmission owner funding?
We think it at least uncertain that FERC can reach the same result after addressing the deficiencies identified in this opinion; indeed, the potential-discrimination justification for FERC's orders seems especially weak. But we think the prospect of disruptive consequences cuts decisively against the premature approval, and precipitate commencement, of construction projects under a tariff of questionable legality. Moreover, that FERC plans a rulemaking to consider interconnection problems and costs also suggests that it should approach those issues on a clean slate. We therefore vacate the orders—with the recognition that the Commission may, as always, file a petition for rehearing in the event it objects to such vacatur on ground we do not perceive—and remand for further proceedings consistent with this opinion.
After the Federal Regulatory Commission rejected a transmission owner's request for unilateral authority to select the funding method for “network upgrades,” certain transmission owners (hereinafter “Ameren”) did not prevail on rehearing and now petition for review of five orders of the Commission.1 In those orders, the Commission addressed the recovery of capital costs and determined there were three fundamental problems with allowing transmission owners unilateral discretion to select the method of funding network upgrades. First, “it [would] allow[ ] the transmission owner ․ [to] subsequently assess the interconnection customer [hereinafter “generator”] a network upgrade charge that is not later reimbursed ․, which may result in discriminatory treatment by the transmission owner of different [generators].” June 2015 Order P 48. Second, it would allow the transmission owner to “deprive the [generator] of other options to finance the cost of the network upgrades that provide more favorable terms and rates.” Id. Third, in contrast to generator funding in which the generator posts security over the term of construction, transmission owner funding would require “the [generator] to post security ․ over the term of the construction phase and over the term of the” contract. Id. P 49. Such increased costs, the Commission found, may “frustrate the development of new, competitive generation, which would contradict a stated purpose of Order No. 2003.” Id. Indeed, adding such cost “with no corresponding increase in service,” the Commission observed, “shares similar characteristics” to a funding option that the Commission had eliminated as unjust and unreasonable. Id. (citing E.ON Climate & Renewables North America, LLC v. Midwest Indep. Transmission Sys. Operator, Inc., 137 FERC ¶ 61,076, P 37 (2011) (“E.ON”) ).
On appeal, Ameren principally contends that the Commission's action is confiscatory insofar as it denies Ameren the ability to earn a return on network upgrades and fails to compensate Ameren for business risk. Petrs Br. 30–35. Ameren maintains that the challenged orders fail to address its most important concern, namely, that absent gaining generator consent, the orders “force [Ameren] to construct, own, and operate transmission facilities without any return, i.e., on a non-profit basis.” Id. at 37–38. The court vacates the challenged orders, concluding that “there is neither evidence nor economic logic supporting [the Commission's] discriminat[ion] theory as applied to transmission owners without affiliated generation assets,” and that the Commission failed to respond adequately to Ameren's non-profit objection. Op. at 3, 21–22. For the following reasons, I respectfully dissent.
As a preliminary matter, it is worth acknowledging the limited scope of the court's review of Commission orders. “[I]n a technical area like electricity rate design,” courts must “afford great deference to the Commission in its rate decisions.” FERC v. Elec. Power Supply Ass'n, 136 S. Ct. 760, 782 (2016) (quoting Morgan Stanley Cap. Grp., Inc. v. Pub. Util. Dist. No. 1 of Snohomish Cty., 554 U.S. 527, 532 (2008) ). As in other agency cases, courts do not “ask whether a regulatory decision is the best one possible or even whether it is better than the alternatives,” but instead ask whether “the agency has ‘examine[d] the relevant [considerations] and articulate[d] a satisfactory explanation for its action[,] including a rational connection between the facts found and the choice made.’ ” Id. at 782 (quoting Motor Vehicle Mfrs. Ass'n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) ). Under the Federal Power Act, factual findings of the Commission that are supported by substantial evidence in the record are “conclusive.” 16 U.S.C. § 825l(b); see also Colo. Interstate Gas v. FERC, 599 F.3d 698, 704 (D.C. Cir. 2010). Furthermore, this court has recognized that it is “perfectly legitimate for the Commission to base its findings ․ on basic economic theory,” as long as “it explain[s] and applie[s] the relevant economic principles in a reasonable manner.” Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520, 531 (D.C. Cir. 2010).
By way of background to understanding the Commission's ongoing consideration of cost allocation in the Midwest region, the critical undisputed fact is that under the Midcontinent System Operator (“MISO”) Tariff, generators bear 90 to 100 percent of the costs of construction of network upgrades. The Commission determined in 2003 that when the generator funds the network upgrade, the generator is to receive credits against transmission service for the amounts funded. Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 104 FERC ¶ 61,103 P 28, 694 (2003) (“Order No. 2003”). The Commission, however, allowed regional transmission organizations “flexibility as to the specifics of the interconnection pricing policy.” Id. P 28. Under MISO's Tariff, transmission owners provided a credit for 50% of the costs borne by generators that funded network upgrades. Midwest Independent Transmission System Operator, Inc., 129 FERC ¶ 61,060, P 3 (2009) (“Midwest ITO 2009”). This changed in 2009. The Commission, acting in “recogni[tion] that cost allocation is one of the most difficult and contentious issues facing the Midwest ISO regional at this time,” id. P 2, approved a proposal by MISO and its transmission owners (including Ameren) to amend MISO's Tariff, id. P 48, “conditioned upon” the filing of a tariff with “a cost allocation methodology ․ as [was] just and reasonable and not unduly discriminatory or preferential,” id. P 49. Under the superseding Tariff, MISO's Option 2 “increase[d] the cost responsibility of a[ ] [generator] to 100 percent of the Network Upgrade costs, with a possible 10 percent reimbursement for projects that were 345 kV and above.” Id. P 3.
In the first of the challenged orders, the Commission, in again addressing the contentious issue of cost allocation in this section 206 proceeding, rejected the request of a transmission owner (“Otter Tail”) for unilateral discretion to choose the funding method for network upgrades. The Commission determined that such discretion could allow transmission owners to discriminate against generators through the imposition of increased costs, thereby “frustrat[ing] the development of new, competitive generation.” June 2015 Order PP 48–49. Examining Article 11.3 of MISO's Generator Interconnection Agreement, the Commission reasoned that the provision appeared unjust and unreasonable and unduly discriminatory or preferential because “it allows the transmission owner the discretion to elect to initially fund the upgrades and subsequently assess the [generator] a network upgrade charge that is not later reimbursed ․ through ․ credits,” and it “may deprive the [generator] of other options to finance the cost of network upgrades that provide more favorable terms and rates.” Id. P 48.
As Joint Intervenors point out, MISO's post-2009 credit policy is “[a] primary reason” the Commission determined that such unilateral discretion was unjust and unreasonable and unduly discriminatory. Jt. Intervenors' Br. 11 (citing June 2015 Order P 3). Intervenors elaborate that by asking for a revised MISO-specific credit policy in 2009 and abandoning responsibility for financing network upgrades, MISO transmission owners “gave up the opportunity to earn a rate of return on the network upgrades.” Id. at 12; see August 2016 Order P 15. Now the generator “bears the full cost of the network upgrades,” save for at most 10%, and the transmission owner “has no asset to roll in its rate base to earn a rate of return.” Jt. Intervenors' Br. 12; see August 2016 Order P 12. MISO's credit policy imposes significant costs on generators: for example, a generator required to fund a $10 million network upgrade, would receive at most $1 million in credits. Jt. Intervenors' Br. 12. Consequently, the credit policy can “cost the [generator] tens of millions of dollars more than the basic Order No. 2003 construct.” Id. at 11–12. To this extent, then, by seeking a MISO-specific tariff amendment, transmission owners' inability to earn a return on generator funding is of their own doing. As Intervenors note, Ameren could earn a return were MISO to revert back to the crediting scheme under Order No. 2003. Id. at 13.
On rehearing, the Commission rejected Ameren's arguments that there was insufficient evidence of discrimination and that the incremental risk of new generator-funded network upgrades would force them to operate on a nonprofit basis.2 The Commission reaffirmed its determination that transmission owners' unilateral discretion over initial funding “would improperly impose costs on [generators].” December 2015 Order P 29. Because generators “bear between 90 to 100 percent of the costs for network upgrades in MISO,” the Commission explained, “it stands to reason that [generators] would have the incentive to find the lowest cost solution to funding” such upgrades. Id. at P 56. Conversely, transmission owners have an incentive to increase costs for the very reason Ameren has challenged the Commission's orders: it seeks a return on top of the cost of the network upgrades. See Id. P 59; June 2015 Order P 48. Thus, as Intervenor American Wind Energy Association pointed out in comments of September 30, 2015 to the Commission, where the generator pays for the upgrade plus a return on 100% of the “capital invested by the transmission owner collected over time, such as a 20 or 30 year period[,]” “[s]imple math shows that self funding [by a transmission owner] is more costly to the [generator].” Ameren does not dispute the Commission's key determination—that generators have an incentive to find lowest cost funding solutions, while transmission owners do not—and has provided no basis for the court to disturb the Commission's findings and determinations.
The Commission reasonably responded to Ameren's argument that removal of transmission owners' unilateral discretion over initial funding improperly deprived it of the ability to recover prudently-incurred transmission costs of service from generators beyond the capital costs of the network upgrades. For instance, the Commission rejected the argument that the initial funding option under Article 11.3 of MISO's pro forma tariff allows transmission owners to recover non-capital costs as contrary to its precedent in Midcontinent Independent System Operator, Inc., 145 FERC ¶ 61,111 at P 41 (2013) (“Hoopeston ”), in which it had determined that doing so would be “unduly discriminatory” because a generator “charged under Option 2 would only be required to pay for the capital costs of network upgrades.” December 2015 Order P 57. The Commission pointed out that Ameren will recover its cost of service through its transmission rates, which will be charged to generators as they take service on the owner's system. Id. P 57 & n.118 (citing Ameren's Attachment O rate formula template). Significantly as well, the Commission rejected the argument that its “proposed Tariff language would not allow transmission owners to ‘set’ a rate of return to directly assign compensation for business risk, such as lawsuits, reliability compliance obligations, environmental and construction risks, to a [generator], inasmuch as such business risk associated with owning transmission are even included in a transmission owner's return ․ under the initial funding option.” Id. P 59 (emphasis added). And the Commission observed that “[t]o the extent MISO believes that the mutual agreement aspect of the [revised] initial funding option raises concerns about the impact of certain costs on particular transmission owners and their customers, MISO may file a proposal under section 205 of the FPA to address such concerns.” Id. P 57. In addition, the Commission noted that it was “simultaneously considering generic interconnection cost issues in a separate rulemaking proceeding in Docket No. RM15-21,” emphasizing that now it was only finding MISO's Tariff “unjust and unreasonable and unduly discriminatory based on the record before us here.” Id. P 60.
Balancing risks in allocating costs, the Commission determined that Option 2 was a just and reasonable rate and available under MISO's Tariff, noting that Ameren “ignores the continued existence of the transmission owner's initial funding option” by mutual agreement with the generator. December 2015 Order P 59. It emphasized that “the obligation to fund these network upgrades rests with the [generator] under MISO's Tariff and as credits are not provided in return for this funding, we find that it is potentially unjust, unreasonable and unduly discriminatory to deprive the [generator] of the ability to provide its own capital funding.” Id. P 59. Citing FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944), the Commission acknowledged that its “task is to allow a public utility the opportunity to offer its investors a return that is commensurate with the risk associated with their investment, as represented by the utility's business and financial risks.” August 2016 Order P 13. It found that where generator funding is used, “the [generator] making the up-front investment bears the business and financial risks associated with financing and constructing the network upgrades.” Id. “Because the transmission owner does not bear that risk,” the Commission determined that “its investors are not exposed to that risk, and it is therefore not necessary for the transmission owner to offer investors a return based on that risk in exchange for their investment of capital.” Id.
The Commission observed further that Ameren “does not allege that funding for network upgrades under Option 2 is confiscatory inasmuch as it provides an insufficient rate of return to a transmission owners; rather, [Ameren] take[s] issue only with the fact that [it] will no longer unilaterally elect that financing option.” Id. P 15 (emphases added). Additionally, the Commission determined, Ameren “had not shown how requiring [a generator] to post security to address risk during construction and allowing [a generator], as opposed to the transmission owner, the initial opportunity to fund network upgrades, precludes transmission owners from operating successfully, maintaining financial integrity, attracting capital, and compensating investors for the risks assumed, in violation of Hope.” Id. P 16. Were Ameren in fact to incur uncompensated costs, such proof could be presented in a future proceeding. See December 2015 Order P 57; see also id. P 60.
The court nevertheless concludes that the challenged orders must be vacated. Op. at 27. The reasons offered by the court for vacatur are unpersuasive because the so-called “deficiencies,” id. at 26, simply ignore the Commission's analysis and Ameren's failure to produce evidence of uncompensated risks as well as the Commission's manner of proceeding, addressing capital costs here and generic interconnection cost issues in a separate docket. The challenged orders reflect the Commission's determination upon assessing a complex and difficult balancing of risks in regard to recovery of costs, and the court owes deference to the Commission's expertise and technical understanding. See Elec. Power Supply Ass'n, 136 S. Ct. at 784.
The court faults the Commission for failing to show why a transmission owner without affiliates would discriminate among generators. Op. at 12–13. But Ameren never argued this point to the Commission. See Request for Reh'g of the Certain MISO Transmission Owners (Jul. 20, 2015); Request for Reh'g of the Indicated Transmission Owners (Jan. 28, 2016); Request for Reh'g of the Indicated Transmission Owners (Sept. 8, 2016). Nor did Ameren argue that the Commission's determination regarding generator funding should be limited to transmission owners with affiliates (such as “Ameren Missouri”). See Op. at 12–13. Ameren disputed only the Commission's determination that undue discrimination may occur if transmission owners could unilaterally elect to fund network upgrades. The court insists that Ameren's incentive theory “can hardly be thought a new argument” given Ameren's “vigor[ ]” in broadly claiming there was no evidence of discrimination. Op. at 13. But an implicit argument about incentives does not meet the statutory requirement and the court offers no pertinent record citation. This court's jurisdiction is limited to grounds “ ‘set forth specifically’ in the petitioner's request for Commission rehearing.” Ind. Util. Reg. Comm'n v. FERC, 668 F.3d 7325, 739 (D.C. Cir. 2012) (quoting 16 U.S.C. § 825l(a) ); see Kelley ex rel. Mich. Dep't of Nat. Res. v. FERC, 96 F.3d 1482, 1487–88 (D.C. Cir. 1996). The court, therefore, vacates the orders based in part on an argument that the Commission never had the chance to consider and over which the court, therefore, lacks jurisdiction. 16 U.S.C. § 825l (b).
That procedural default aside, the court could hardly dispute that Ameren has “a competitive motive” to favor affiliated generators over other generators. The Commission addressed this circumstance in Order No. 888 and the Supreme Court thereafter observed that “utilities' control of transmission facilities gives them the power either to refuse to deliver energy produced by competitors or to deliver competitors' power on terms and conditions less favorable than those they apply to their own transmissions.” New York v. FERC, 535 U.S. 1, 8–9 (2002); see Nat'l Ass'n of Reg. Utility v. FERC, 475 F.3d 1277, 1279 (D.C. Cir. 2007). The court recognized in a monopoly context that transmission owners “naturally wish to maximize profit” and “can be expected to act in their own interest ․ even if they do so at the expense of lower-cost generation companies and consumers.” Transmission Access Policy Study Grp. v. FERC, 225 F.3d 667, 684 (D.C. Cir. 2000). The Commission has identified a similar motivation in its interconnection precedent in determining, in view of MISO's post-2009 credit policy, that unilateral transmission owner control over initial funding of upgrades “creates unacceptable opportunities for undue discrimination.” E.ON, 137 FERC ¶ 61,076, P 38. So too in the challenged orders. In short, even if the court had jurisdiction, its vacatur is overbroad.
This court has recognized that the Commission may properly take action “premised not on individualized findings of discrimination by transmission providers, but on a fundamental systemic problem.” Transmission Access Policy Study Grp, 225 F.3d at 684. Here, the Commission was confronted with the fundamental, systemic problem of the recovery of capital costs, see August 2015 Order P 17, where transmission owners had threatened to withdraw from a regional organization, see Midwest ITO 2009, P 7, and now sought to impose increased costs on generators without increasing service based on a unilateral discretionary choice of the method of funding network upgrades. June 2015 Order P 52. As discussed, the Commission identified the contrasting economic motivations of transmission owners and generators, see, e.g., December 2015 Order PP 29, 56, 59; June 2015 Order P 48, in determining that the transmission owner funding option would involve imposition of a network upgrade charge, June 2015 P 48, and a more onerous security requirement, December 2015 Order P 29, and loss to generators of the opportunity to secure more favorable financing, id.
In addition to relying on “reasonable economic propositions,” see S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41, 65 (D.C. Cir. 2014), and its precedent, the Commission pointed to empirical evidence that transmission owners' unilateral election to initially fund network upgrades could result in increased costs to generators or be implemented in an unduly discriminatory way. The Commission looked to the Border Winds protest where evidence was introduced that a transmission owner's initial funding election increased the costs to the generator. December 2015 Order P 33. The court characterizes the study as “flawed,” Op. at 12 n.10, but this is an overstatement. The Commission itself recognized that the transmission owner's proposed fixed rate was not calculated in conformity with a clarification in Commission precedent but concluded “the case record in Border Winds” nonetheless showed increased generator costs, because Border Winds never indicated that a “lower fixed charge rate ․ would still not represent an increase in cost compared to” generator funding. December 2015 Order P 33. Further, the Commission pointed out, its clarifying precedent had not considered the effect of a transmission owner's unilateral election of initial funding on relative capital costs. See id. P 34.
Indeed, the court acknowledges that “it is certainly possible, if not probable” that generators could be deprived of less costly financing options. Op. at 15; see June 2015 Order P 49; Jt. Intervenors' Br 13–14 (citing comments of Intervenor American Wind Energy Association). Yet the court dismisses without serious engagement, see Op. at 15–16, the Commission's extended consideration of the difficulties presented by cost allocation in the Midwest region, see Midwest ITO 2009, P 2, aggravated by MISO's post-2009 credit policy, as well as the Commission's determination to adhere to the principles underlying Order No. 2003, so as to prevent undue discrimination, preserve reliability, increase energy supply, and lower wholesale prices for customers by increasing competition, and its interconnection precedent in Hoopeston and E.ON to ensure transmission owners could not unilaterally increase costs to generators.
The court also raises the specter of additional uncompensated risks and concludes the Commission “inadequately considered” Ameren's argument. Op. at 17. Were this so, then a remand for further explanation, not vacatur, would be appropriate. See Allied–Signal v. Nuclear Reg. Comm'n, 988 F.2d 146, 151 (D.C. Cir. 1993). But it is not so. The court concludes the Commission “makes no real attempt to holistically assess all of the various risks and benefits to the transmission owner caused by the addition of the upgrade facilities.” Op. at 16. That, at best, is an overstatement. The court's analysis is doubly flawed.
First, the Commission's response is understandable because Ameren offered only bare generalities about its uncompensated costs, but no specifics. December 2015 Order P 59. In seeking rehearing, Ameren referred broadly and baldly to concern about “lawsuits, reliability compliance obligations, environmental risk, and construction risk, among others.” Request for Reh'g of the Indicated Transmission Owners (Sept. 8, 2016), at 13. In a footnote, the court labors unsuccessfully to recast Ameren's general claims as specific ones. See Op. at 17 n.14. Absent any evidence of specific uncompensated costs, however, what Ameren presented to the Commission was a claim for generic relief that was being addressed in a separate docket. December 2015 Order PP 40, 60. The court's reliance, Op. at 24, on American Telephone & Telegraph Co. v. FCC, 978 F.2d 727, 729 (D.C. Cir. 1992), is misplaced. Here there was no “administrative shell game.” Id. at 731–32. The Commission stood ready to address Ameren's business risk claims but was stymied from doing so in this adjudicatory proceeding because Ameren failed to present any specific evidence. In deciding to address generic claims in a separate proceeding, the Commission was “merely exercising its well-established discretion to ‘order [its] own docket[ ].’ ” Algonquin Gas Transmission. Co. v. FERC, 948 F.2d 1305, 1315 (D.C. Cir. 1991) (alterations in original); see U.S. Tel. Ass'n v. FCC, 359 F.3d 554, 588 (D.C. Cir. 2004).
Second, the court ignores that Ameren never points to any explanation it offered to the Commission of how it faced any additional insurance, construction, or environmental risk as a result of a particular funding method over another. It is undisputed that under MISO's Tariff, as the Commission found, Ameren as a transmission owner is compensated for operational and management costs. December 2015 Order P 47 n.118 (citing MISO, FERC Electric Tariff, att. O). Transmission owners are also required to purchase Employers' Liability and Workers' Compensation Insurance, Commercial General Liability Insurance, Comprehensive Automobile Liability Insurance, and Excess Public Liability Insurance regardless of how network upgrades are funded. MISO, FERC Electric Tariff, att. X, app. 6 (GIA) § 18.4 (minimum insurance requirements). Generators, in turn must post security, under MISO's Tariff, “in order to address risk during construction.” December 2015 Order P 59. Ameren does not suggest the risk of an environmental violation is anything other than equal under either initial funding method. In the Commission's words:
Indicated MISO Transmission Owners have not explained how allowing [a generator] to fund network upgrades under Option 2 fails to protect against unspecified ‘other risks associated with construction (not otherwise addressed by insurance)’ or operating risks due to requirements “to operate customer-financed assets in compliance with applicable Reliability Standards,” violations of which could “result in penalties that would not be recoverable from customers.”
August 2016 Order P 17 (quoting Request for Reh'g at 22).
Furthermore, the Commission determined that network upgrades could mitigate transmission owners' reliability risk by reducing congestion. August 2016 Order P 17. In the post-Order No. 888 context, this court has recognized that network upgrades “provide system-wide benefits.” NARUC, 475 F.3d at 1285. The court characterizes the benefits of network upgrades as “a possibility to be explored,” Op. at 17, rather than a determination to which the court owes deference. This misses the mark. The Commission's point was that in view of the acknowledged benefits of network upgrades, Ameren had not explained how network upgrades “should be considered additive to the reliability risk,” August 2016 Order P 17, much less shown that it faced additional reliability risk as would justify setting aside the challenged orders as confiscatory. The determination that Ameren had not shown additional reliability risk deserves deference.
Having failed to identify any unrecoverable additional costs traceable to the challenged orders, Ameren attempts to shift its “heavy” burden on rehearing, see Hope, 320 at 602, by contending that the Commission “ignores the fundamental reality that all new facilities bring incremental risk of operation.” Reply Br. 22. Of course, that simply elides the question of whether there are any risks that are uncompensated, for not every regulatory decision requiring action by a regulated entity gives rise to a corresponding entitlement to a return—“regulation does not insure that the business shall produce net revenues.” Hope, 320 U.S. at 603 (internal quotation marks omitted). The court accepts that allowing generators to select the initial funding method “might remain bearable so long as the generator-funded upgrades growing inside the grid remain tiny relative to their host.” Op. at 20. And although the Commission acknowledges that independent power generators have an increasing presence since Order No. 888, Rspdt's Br. 4, the Commission's statutory concern is that “competition depend[s] on generators' having adequate means of getting their power to market.” NARUC, 475 F.3d at 1279 (internal citation omitted). Unbundling under Order No. 888 required equal access for generators to transmission facilities, see id., and in Order No. 2003, the Commission standardized procedures for generator interconnections. The challenged orders reflect adherence to those principles.
Under the circumstances, there is no basis for the court to state that the Commission made “no real attempt to holistically assess” risks and benefits, Op. at 16, given Ameren's evidentiary failure, the Commission's determination regarding reliability risk, and its broader analysis of the allocation issue based on the record before it. Instead, the court has ignored inconvenient record facts and the Commission's fulsome response to Ameren's arguments, including its explicit statement on the limits of its ruling on MISO's Tariff in the challenged orders. December 2015 Order P 60. The Commission's assessments of how the risks should be balanced in allocating capital costs is a quintessential task involving Commission expertise and technical understanding that is entitled to deference by the court. See Elec. Power Supply Ass'n, 136 S. Ct. at 784.
The court also mistakenly accepts Ameren's bald assertion that the challenged orders will force transmission owners to operate on a nonprofit basis in violation of Hope. Op. at 18–22. In Hope, the Supreme Court addressed whether natural gas rates threatened a company's overall financial integrity; it nowhere suggested that the Federal Power Act entitled a company to the ability to earn a favorable return on every portion of its business. See Hope, 320 U.S. at 605. Addressing a similar issue under a state statute, the Supreme Court made clear that the focus was on whether “[t]he overall impact of the rate orders” would “jeopardize the financial integrity of the companies.” Duquesne Light Co. v. Barasch, 488 U.S. 299, 310 (1989). The court here acknowledges that “[i]nvestors ․ invest in entire enterprises, not just portions thereof.” Op. at 19. Why that is not also a permissible perspective for the Commission when weighing risks relating to the recovery of capital costs is not explained.3
The issues now before the court are whether the Commission reasonably determined under the Federal Power Act, based on the evidence presented, that it is (1) unduly discriminatory to allow transmission owners unilaterally to select a financing scheme that increases costs for a generator seeking interconnection services, and (2) just and reasonable to allow a generator to choose to pay the upfront capital costs of network upgrades required for interconnection, with the result that those capital costs are excluded from the transmission owner's rate base. The court appears to assume that generator-funded upgrades will comprise a “significant fraction” of Ameren's overall business. Op. at 25 n.18. But the court points to no Ameren financial data that would support its prediction that the Commission's decision unlawfully interferes with Ameren's “business model.” Op. at 18. An affidavit it cites from the Otter Tail Power Company describing a number of upcoming interconnection projects, see Op. at 25 n.18, hardly suffices to carry Ameren's “heavy” burden on rehearing to disturb the Commission's balancing of risks. See Hope, 320 at 602.
The court's discounting of the Commission's reference to Ameren's opportunity to present evidence of uncompensated risks in a future proceeding, Op. at 22–23; December 2015 Order P 57, fares no better. The court states that “fines and penalties for violations of mandatory reliability standards and environmental regulations are generally charged directly to the utility, not passed through to customers via rate increases.” Op. at 21; see Pet'rs Br. 33 n.1. The stipulated agreement in In re SCANA Corp., 118 FERC ¶ 61,028 (2007); see Op. at 22, nowhere suggests fines and penalties are unrecoverable as a matter of law. Even assuming the general practice is that fines and penalties are not passed on, the court cites no authority the Commission erred as a matter of law in holding out the evidentiary opportunity for Ameren. See Op. at 22. The Commission's rejection of Ameren's arguments as to uncompensated business risks and forced “non-profit” operation rested on Ameren's failure to proffer specific evidence. See August 2016 Order PP 16–17. Given the Commission's stated position in the challenged orders, there is no basis for the court to conclude the outcome of a future hearing is a “foregone conclusion.” Op. at 23. The court's vacatur thus overshoots its target and jumps the gun.
The Federal Power Act mandates the Commission ensure that rates are “just and reasonable” and not unduly discriminatory, 16 U.S.C. § 824d(a)-(b). A purpose of Order No. 2003 is to “increase[e] the number and variety of new generation that will compete in the wholesale electricity market.” Order No. 2003 at P 1. Given the established economic motivations and the post-2009 MISO credit policy's treatment of capital costs, the Commission reasonably and adequately explained its assessment of how risks should be balanced between investor and customer interests. See Hope, 320 U.S. at 603. The Commission recognized the complex and contentious nature of the issue in the Midwest region, conditionally approved the 2009 proposal of MISO and its transmission owners to amend MISO's Tariff, and has now, based on the record before it, determined, in its expert judgment, that Ameren's arguments for unilateral control of the method of funding network upgrades must be rejected and generators allowed to choose the funding method. The same two funding options for network upgrades that were available prior to the challenged orders remain available; the only change is that the choice belongs to generators with an incentive to minimize costs rather than to transmission owners with an incentive to impose additional costs that could frustrate the development of new generation.
In doubting the adequacy of the Commission's determination of the appropriate allocation of capital costs in MISO, the court asserts that the Commission failed to address the concern that “when portions of a business are unprofitable, it detracts from the attractiveness to investors of the business as a whole.” Op. at 20. But the Commission directly addressed that concern when it found that Ameren had failed to present evidence showing a threat to its overall financial integrity as would warrant finding the challenged orders were confiscatory. August Order 2016 P 16. Somehow the court overlooks that Ameren's laser-like focus is on regaining unilateral control over funding network upgrades. See August 2016 Order P 15. Hope does not require this, for reasons the Commission explained. Commission precedent likewise points the other way. Absent evidence that the challenged orders will cause generator-funded network upgrades to occupy so “significant [a] fraction” of Ameren's business as would jeopardize its overall financial integrity, the Commission's reasons for rejecting unilateral transmission owner control were not arbitrary or capricious. Vacating the challenged orders at this juncture is inconsistent with the record before the Commission, its findings and determinations in allocating capital costs, and the court's deferential standard of review.
1. MISO operates in fifteen states located largely within the midwestern United States, along with the Canadian province of Manitoba.
2. For a detailed description of the series of FERC orders that led to the development of competitive power generation markets and the creation of MISO, see Wisconsin Public Power, Inc. v. FERC, 493 F.3d 239, 246–50 (D.C. Cir. 2007); Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1363–65 (D.C. Cir. 2004).
3. Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ¶ 31,160, order on reh'g, Order No. 2003-B, FERC Stats. & Regs. 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ¶ 31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007).
4. E.ON Climate & Renewables North America, LLC v. Midwest Indep. Transmission Sys. Op., Inc., 137 FERC ¶ 61,076 (Oct. 20, 2011).
5. Under generator funding, the transmission owner does provide a refund of the reimbursable portion of construction costs—which amount to ten percent of capital costs for projects rated at 345 kilovolts or higher—in the form of a credit toward transmission services charged to the interconnecting generator. The generator receives no reimbursement for the remaining ninety percent of these larger projects.
6. This unexecuted FCA was submitted pursuant to Section 205 of the Federal Power Act, 16 U.S.C. § 824d (2012).
7. Midwest Indep. Sys. Operator, Inc., 141 FERC ¶ 61,220 (Jun. 18, 2015) (“June 2015 Order”).
8. This language suggests that FERC thought transmission owner funding was unjust and unreasonable only because it was discriminatory. However, in the final orders the Commission seems to rest on two separate grounds: potential discrimination by transmission owners among generators, and excessive costs charged to generators with no increase in service, which FERC found to be unjust and unreasonable. See Otter Tail Power Co. v. Midcontinent Indep. Sys. Operator, Inc., 153 FERC ¶ 61,352 at P 29, 32, 33 (Dec. 29, 2015) (“December 2015 Order”); Otter Tail Power Co. v. Midcontinent Indep. Sys. Operator, Inc., 156 FERC ¶ 61,099 at P 15, 19 (Aug. 9, 2016) (“August 2016 Order Denying Rehearing”).
9. In the third and fourth of the orders under review, FERC rejected another petition from six transmission owners (“August 2016 Order Denying Rehearing”) and accepted MISO's compliance filing to remove a transmission owner's ability to choose between funding options from the MISO Tariff (“August 2016 Order on Compliance”). In the fifth and final order on review in this case (“October 2016 Order”), the Commission denied a procedurally-oriented request for rehearing, with reference to its December 2015 Order and August 2016 Orders.
10. The only study alleging evidence of disparate costs charged generators was conceded by FERC to be flawed. See December 2015 Order at P 33.
11. See, e.g., Calpine Corp. v. FERC, 702 F.3d 41, 43 (D.C. Cir. 2012) (“Order 888 was successful in causing major utilities nationwide to divest most of their generating facilities ․”). See also generally Wisconsin Public Power, Inc. v. FERC, 493 F.3d 239, 246–50 (D.C. Cir. 2007) (describing the series of Commission orders that led to the development of MISO and encouraged divestiture of generation assets).
12. As such, of the two alleged sources of increased costs under transmission owner funding—a missed opportunity to seek alternative, cheaper funding and a more onerous security requirement—the second seems to collapse into the first: any alternative financing package must account for the risk of loss, whether through an explicit security requirement (such as a letter of credit) or an implicit willingness to bear that risk expressed through a higher financing rate.
13. This recovery is alleged to occur through a process by which transmission owners recoup their recognized expenses for such line items as operations and maintenance. See December 2015 Order at P 57 & n. 118.
14. The dissent contends that Petitioners offered “only bare generalities about its uncompensated costs, but no specifics.” Dissent at 13. But risks—which are contingent possibilities of future adverse events—must be described in hypothetical terms. And Petitioners did offer specific examples to support the general argument that when they are denied the opportunity to fund construction that occurs within their grid, “the return earned is disproportionate to the size, complexity, and risks of the system the transmission owner owns and operates.” Request for Rehearing of the Indicated Transmission Owners, Docket Nos. EL15-68, EL15-36 (FERC January 28, 2016) at 14. Indeed, they cited FERC's own summary of these risks, noting that FERC had addressed only one small subset (construction risks covered by financial security). Id. at 20–22. They offered compliance with Reliability Standards as just “one example of such risk” that had not been addressed. Id. at 22. And their subsequent discussion before us of uncompensated penalties stemming from electrocutions and blackouts caused by untrimmed trees demonstrates the eminent sensibility of recognizing “the fundamental reality that all new facilities bring incremental risk of operation.” Reply Br. 22; see id. at 17–24; Oral Arg. at 5:07–6:20.
15. See, e.g., December 2015 Order at P 59 (“Our decision does not preclude the transmission owner from earning a return on these network upgrades from the interconnection customer where the transmission owner and the interconnection customer mutually agree ․ any return that was available to a transmission owner when the initial funding election was made on a unilateral basis by the transmission owner is still available when the transmission owner's initial funding option is made on a mutually agreed upon basis.”).
16. See Petition for Rulemaking of the American Wind Energy Association to Revise Generator Interconnection Rules and Procedures, Docket No. RM15-21 (FERC June 19, 2015) at 5 (“Reforms to improve certainty of network upgrade costs: ․ ii. Allow a Transmission Provider to fund network upgrades (self-funding) only if agreed to by the Interconnection Customer.”); id. at 50–52 (recommending that “The GIPs Should Require the Interconnection Customer's Agreement for the Interconnecting Transmission Owner to Self–Fund Network Upgrades,” id. at 50).
17. Nor is it necessary to reach the petitioning transmission owners' argument that FERC departed from its precedent without justification, or that its orders here are illegal because they constitute a “novel” form of ratemaking under Hope. These issues may become appropriate for our consideration in the event that FERC adequately supports its decision.
18. We think it noteworthy here that FERC, the petitioning transmission owners, and the intervening independent generators have all recognized that many interconnecting generators would prefer to use generator funding if permitted by FERC. And as one engineer noted before FERC, the backlog of new projects is high, causing a situation in which “Otter Tail and its neighboring transmission systems are rapidly confronting the need to fund and construct both direct and indirect Network Upgrades for new generation.” Affidavit of Dean Pawloski, Principal Engineer, Otter Tail Power Company at P 6 (January 12, 2015). The prospect, then, that today's network upgrades will cumulatively constitute a significant fraction of tomorrow's grid renders the petitioning transmission owners' concern more credible.
1. Four orders denied rehearing; a fifth order addressed compliance. Midcontinent Independent System Operator, Inc., Order Denying Rehearing, Granting in Part and Denying in Part Complaint, and Instituting Section 206 Proceeding, 151 FERC ¶ 61,220 (June 18, 2015) (“June 2015 Order”); Otter Tail Power Company v. Midcontinent System Operator, Inc., Order Denying Rehearing and Granting Clarification, and Directing Compliance Filing, 153 FERC ¶ 61,352 (Dec. 29, 2015) (“December 2015 Order”); Otter Tail Power Company v. Midcontinent System Operator, Inc., Order Denying Rehearing, 156 FERC ¶ 61,099 (Aug. 9, 2016) (“August 2016 Order”); Midcontinent System Operator, Inc., Order on Compliance, 156 FERC ¶ 61,098 (Aug. 9, 2016); Midcontinent Independent System Operator, Inc., Order Denying Rehearing, 157 ¶ 61,013 (Oct. 7, 2016).
2. Request for Reh'g of the Certain MISO Transmission Owners (Jul. 20, 2015); Request for Reh'g of the Indicated Transmission Owners (Jan. 28, 2016); Request for Reh'g of the Indicated Transmission Owners (Sept. 8, 2016).
3. The court's chastisement of the Commission, based on its counsel's purported response to a hypothetical question during oral argument before the court, is misplaced. The court suggests that counsel “cross[ed] a rather significant conceptual line” by agreeing that transmission owners would not be entitled to a return on a billion-dollar network upgrade. Op. at 20–21. But the transcript shows that Commission counsel stated that transmission owners could seek a “profit” in such a future case if there were an “evidentiary basis” that the upgrade posed a “demonstrated specific risk.” Oral Arg. at 39:30–40:51.
Silberman, Senior Circuit Judge:
Dissenting opinion filed by Circuit Judge Rogers.