Cost Allocation: Clarity on the Legal Standard, But Not How to Meet It
In its 2009 decision in Illinois Commerce Commission v. FERC,3 the US Court of Appeals for the Seventh Circuit vacated and remanded orders in which the federal regulatory agency had accepted a system-wide allocation of the costs of high-voltage electric transmission expansion projects within the PJM Interconnection RTO. The court’s majority ruled that, to approve such a system-wide allocation of costs on an integrated transmission grid, FERC must have substantial evidence that the costs imposed on the system’s various user-constituencies are roughly commensurate with the benefits they receive from the relevant facilities. The court stated explicitly that FERC cannot rely solely on a presumption that all users of an integrated transmission network benefit from improvements to the network’s reliability, but instead must compare the allocated costs with the benefits expected to be realized by those who will pay the assigned costs.4
ICC suggested to some observers a more rigorous standard for judicial review of FERC’s cost allocation rulings than was generally discerned from prior court decisions.5 Moreover, the Seventh Circuit’s decision did not explain the nature or extent of the evidence that would be necessary to justify a system-wide allocation of the costs of network improvements. This potentially raised the prospect of serious regulatory delays in the construction of the vast amounts of new transmission that are needed to sustain the reliability of the grid, and to support large-scale development of renewable electric generation resources. Though some new lines are being developed independently as merchant transmission facilities,6 cost allocation remains a source of controversy with respect to new high-voltage lines and upgrades within and across two or more interstate transmission grids operated by FERC-approved RTOs and ISOs.
The ICC majority declined to defer to FERC’s expertise in rate-making, explaining that it is “not authorized to uphold a regulatory decision that is not supported by substantial evidence on the record as a whole, or to supply reasons for the decision that did not occur to the regulators.”7 The court found that FERC failed to identify substantial evidence to support the agency’s approval of assigning costs pro rata for new transmission facilities at or above 500 kV to all loads in the PJM region based on their consumption of the energy transmitted on the PJM grid (i.e., a “postage-stamp” allocation). The court summarized FERC’s reasons for approving the postage-stamp cost allocation as follows: “some of PJM’s members entered into similar pro rata sharing agreements with each other more than forty years ago and would like to follow that precedent,” “figuring out who benefits from a new transmission facility and by how much is very difficult and so generates litigation,” and “everyone benefits from high-capacity transmission facilities because they increase the reliability of the entire network.”8 In response, the court stated that “no data are referred to in FERC’s two opinions,”9 and enumerated several evidentiary deficiencies in FERC’s rationale: “No lawsuits are mentioned. No specifics concerning difficulties in assessing benefits are offered. No particulars are presented concerning the contribution that very high-voltage facilities are likely to make to the reliability of PJM’s network. Not even the roughest estimate of likely benefits to the objecting utilities is presented.”10 In sum, the court concluded, FERC had no evidence to support the reasons it gave for its decision.
The Seventh Circuit nevertheless explained that FERC is not required “to calculate benefits to the last penny, or, for that matter, to the last million or ten million or perhaps hundred million dollars.”11 Rather, if FERC “has an articulable and plausible reason to believe that the benefits are at least roughly commensurate with [the objecting] utilities’ share of total electricity sales in PJM’s region, then fine; [FERC] can approve PJM’s proposed pricing scheme on that basis.”12 The court acknowledged that its “review of decisions by FERC is deferential,” and that it requires only that FERC “have made a reasoned decision based upon substantial evidence in the record.”13 However, the court concluded, FERC had failed to do that.14
FERC did not construe ICC to establish a new standard for review of cost allocation cases. In response to the Seventh Circuit’s remand, the agency again ruled that PJM’s previous allocation method based on power flows, or “DFAX,” is an unjust and unreasonable method of allocating the costs of the 500 kV and above transmission upgrades. It went on to reaffirm its ruling that the costs of such facilities should be allocated on a postage-stamp basis to load in each transmission rate zone.15
FERC emphasized the Seventh Circuit’s acknowledgments that some expansion projects may benefit the regional transmission grid as a whole, and that benefits to each user or class of users of the grid need not be precisely quantified.16 Therefore, FERC said, the Seventh Circuit’s decision requires only a showing that some customers in zones other than those currently flowing power over facilities that need upgrading will use or benefit from the improved facilities.17 The heart of its revised rationale, however, was that PJM’s regional planning process creates an integrated transmission network that produces benefits for “all parties connected to the transmission system regardless of nominal power flows.”18 It is therefore reasonable to conclude, FERC said, that all users of the integrated network share these benefits roughly in proportion to their use of the grid.19 Petitions for review of the orders on remand are now pending in the Seventh Circuit.
FERC’s ruling in the remand from ICC remains true to its intervening approvals of partial “socialization” of the costs of transmission upgrades in two other RTO regions,20 and its invitation for similar allocations in its Order No. 1000.21 One of these rulings, related to cost recovery for large, high-voltage “multi-value” projects, or “MVPs,” in the RTO grid operated by the MidContinent Independent System Operator (MISO)22 recently brought another system-wide allocation dispute to the Seventh Circuit.
This time the court was asked to review FERC’s approval of MISO’s recovery of costs associated with investment of as much as $5 billion in MVP projects, based entirely on the amounts of energy each of MISO’s members withdraws from the MISO grid (as opposed to recovery, in whole or in part, through fixed charges). In this case, the court found that substantial evidence in the record supported FERC’s approval of MISO’s proposal to allocate the MVP costs on a system-wide basis. The court noted that, “[t]o qualify as an MVP a project must have an expected cost of at least $20 million, must consist of high-voltage transmission lines (at least 100 kV), and must help MISO members meet state renewable energy requirements, fix reliability problems, or provide economic benefits in multiple pricing zones.”23 The court further observed that “[n]one of these eligibility criteria ensures that every utility in MISO’s vast region will benefit from every MVP project, let alone in exact proportion to its share of the MVP tariff.”24
Nevertheless, the court upheld FERC’s orders. The court explained that, even if some MISO members “would not benefit from MVPs that help utilities meet state renewable energy requirements[,]” they still would “benefit by virtue of the criteria for MVP projects relating to reliability and to the provision of benefits across pricing zones.”25 The court cited FERC’s reliance on MISO’s “estimates that there would be cost savings of some $297 million to $423 million annually because western wind power is cheaper than power from existing sources, and that these savings would be ‘spread almost evenly across all Midwest ISO Planning Regions.’”26 In addition, MISO had “estimated that the projected high-voltage lines would reduce losses of electricity in transmission by $68 to $104 million, and save another $217 to $271 million by reducing ‘reserve margin losses.’”27
The court recognized that “[i]t’s impossible to allocate these cost savings with any precision across MISO members.”28 The court reasoned, however, that, while “MISO’s and FERC’s attempt to match the costs and the benefits of the MVP program is crude; if crude is all that is possible, it will have to suffice.”29 Reiterating its reasoning in ICC, the court explained that, “if FERC ‘cannot quantify the benefits [to particular utilities or a particular utility]’” but nonetheless has “an articulable and plausible reason to believe that the benefits are at least roughly commensurate with those utilities’ share of total electricity sales in [the] region, then fine; [it] can approve [the pricing scheme proposed by the Regional Transmission Organization for that region] . . . on that basis.’”30 In other words, the court upheld FERC’s approval of MISO’s proposal to allocate MVP costs on a system-wide basis because, this time, the agency relied on substantial, documented evidence of widespread (even if not evenly distributed) benefits from the new facilities.
ICC II clearly is good news for the transmission industry and for renewable power interests. If the case had fulfilled the putative promise of ICC to impose a stricter standard for allocating the costs of new transmission investments among the users of the affected regional grid, it might have added significantly to what are already often daunting hurdles to the completion of high-voltage transmission projects. Still, even with its general endorsement of the prevailing view that all network improvements inherently benefit all users to some degree, ICC II does not necessarily remove all cost allocation obstacles for transmission developers. The Seventh Circuit’s decisions together still offer a challenge to those who advocate socialization of the costs of high-voltage transmission projects. Such system-wide allocations can be lawful, but those who support them have to document, and have to quantify to the extent reasonably feasible, at least some of the benefits of such projects throughout the region whose ratepayers would pay for the facilities in question.
Establishing how to satisfy this standard is crucial. Though transmission remains a relatively small portion of the delivered cost of electricity to consumers, enormous capital investments are needed to modify the grid for 21st century flow patterns and to ensure continuing compliance with reliability requirements. The Edison Electric Institute (EEI) forecasts that transmission investment by investor-owned utilities for 2013 alone will surpass $15 billion, and will be approximately $51.1 billion through 2023.31 Much of the new high-voltage transmission that has been built or planned is in ISO/RTO regions. For example, according to The Brattle Group, Inc., an economic consultancy, approximately $30 billion in projects have already been approved in the transmission plans of RTOs.32 That is not by coincidence. ISOs and RTOs generally have more robust regional planning processes than other transmission providers, and have established more transparent rules governing cost allocation for new transmission facilities.33
Achieving large-scale penetration of renewable generation, however, will mean a lot more new transmission than is already promised. Such facilities will be needed not only to meet the renewable portfolio standards or goals (RPS) that 37 states and the District of Columbia34 already have enacted, but to transport energy to load centers from the remote locations that offer the best sites for wind and central station solar generation.
The 2012 Renewable Electricity Futures Study by the Department of Energy’s National Renewable Energy Laboratory (NREL)35 underscores this point. NREL’s study concisely summarizes why significant transmission investment is essential to integrating renewable generation into the US electric system at a national scale:
Today’s power system has evolved over the past 130 years from isolated, distributed power plants that serviced local load. . . . Traditionally, the resource adequacy of the system has been based on dispatchable generation under the control of system operators. In addition, with the notable exception of hydroelectric generation, location-constrained resources have not been used.36
NREL’s analysis nevertheless led it to the “central conclusion . . . that renewable electricity generation from technologies that are commercially available today, in combination with a more flexible electric system, is more than adequate to supply 80% of total U.S. electricity generation in 2050 while meeting electricity demand on an hourly basis in every region of the United States.”37 Accomplishing such an ambitious goal would require considerably greater operational flexibility in the grid and its dispatchable generation resources, greater implementation of demand response, as well as considerable new transmission. According to one analysis, NREL’s work shows that the transmission component for achieving 80 percent penetration of renewable energy generation by 2050 could be accomplished with investments of approximately $6.4–$8.4 billion per year, amounts generally comparable to those that utilities and merchant transmission companies have invested in recent years.38 This overlooks a crucial element, however. As NREL explained, geography and economics dictate that truly large-scale expansion of renewable generation depends disproportionally on new, long-distance transmission capability:
For renewables, the tradeoff between nearby, but lower-quality resources, versus distant, but higher-quality resources, with the additional cost of the transmission system, is a particularly important consideration.
[I]t may often be more economic to build transmission from sites with high-quality renewable resources (or similarly, use nearby, existing lines more efficiently), than to site wind or solar installations in locations with lower-quality resources that are nearer to load. The cost of the additional transmission is often a small fraction of the cost of additional generation equipment at the lower-quality site needed to provide equivalent amounts of electrical energy. Hence, the delivered cost of energy produced at the higher-quality site is lower than the energy cost from the lower-quality site, even though the former requires additional transmission.39
Therein lies the rub. The kinds of long-distance transmission lines the NREL study hypothesizes are the most difficult projects to execute:
The challenge is that the most essential lines for a high-penetration renewable electricity future are often the most difficult ones to build. These transmission facilities typically must span hundreds of miles, carry price tags of hundreds of millions of dollars, and most significantly, cross many boundaries of a balkanized regulatory framework that emerged almost a century ago for local monopolies organized around central power plants serving retail markets. This institutional structure is fundamentally unsuited to the task of planning and building modern, efficient, regional and interregional transmission.40
Order No. 1000 Could Generate Problems
Though not specifically aimed at the issue just described, FERC’s Order No. 100041 addresses it indirectly, among various new rules that some observers suggest “may prove beneficial to advance transmission projects for renewable energy and other merchant power projects.”42 Three aspects of the order are particularly relevant here.
First, Order No. 1000 requires every public utility subject to FERC’s jurisdiction under the Federal Power Act to participate in a regional transmission planning process that periodically produces a regional transmission expansion plan.43 All regional planning must provide opportunities for participation by legitimately interested stakeholders, and must take into account “public policy requirements.”44 Public policy requirements include all statutes and regulations promulgated by a relevant federal or state authority and, therefore, include any state-mandated RPS.45 FERC’s rule does not define “regional,” other than to specify that a single utility’s service area cannot constitute a region for purposes of complying with the regional planning requirement.46 Adjoining regions must “coordinate” the planning of interregional facilities, i.e., facilities that would be located partly in each of two or more planning regions. Such interregional planning, however, does not have to produce a formal interregional plan.
Order No. 1000 also is important in the present context because it expressly forbids regional planning processes from including a preference (referred to as a “right of first refusal,” or ROFR) for incumbent transmission owners in the construction of new regional transmission projects.47 Particularly in regions where one or more incumbent utilities is vertically integrated, this provision, at least in theory, could provide additional opportunities for new transmission projects that will deliver renewable energy from distant sources. That is far from certain, however. FERC’s order includes no means of compelling two or more regions to consider a proposed interregional project, and it expressly rejects any requirement of coordinated planning at the interconnection-wide level. Moreover, there is much opposition to the elimination of ROFRs in FERC-jurisdictional tariffs, and the issue figures to have a prominent role in the several pending appeals of Order No. 1000 in the US Court of Appeals for the District of Columbia Circuit.
A third principal feature of Order No. 1000 is its establishment of parameters for allocation of the costs of new regional and interregional transmission facilities. Order No. 1000 does not prescribe how any such costs must be allocated. Instead, it establishes six principles with which all regional and interregional cost allocation regimes must comply. Foremost among these is that all proposed cost allocations must be “at least roughly commensurate with estimated benefits” of the relevant facilities to those who will pay for them.48 This, of course, is precisely the terminology of ICC’s test for a valid cost allocation under the FPA.49 FERC’s order went on to establish five other allocation principles:
- Costs may be allocated only to those who benefit from the indicated transmission facilities, except by agreement.
- If a cost/benefit threshold is used to assess which projects are viable or justifiable, it cannot be higher than 1.25, unless a higher threshold is specifically justified.
- The costs of regional transmission projects cannot be allocated to other transmission regions except by agreement.
- The methodologies selected for determining benefits and beneficiaries, and for allocating cost responsibility must be “transparent,” that is, they must be documented sufficiently to permit stakeholders to understand them and to assess how they were applied.
- Different cost allocation methods can be used for different types of transmission projects (e.g., for projects to maintain reliability vs. “economic” or “public policy” projects).50
The ICC decisions reaffirm that allocated costs must be reasonably commensurate with anticipated benefits, and that neither the extent nor the sufficiency of such benefits may be inferred from the premise that all users of the grid benefit from all improvements to it. Order No. 1000 confirms that the cost allocation devil is still very much alive in the details of how the benefits of new regional and interregional transmission facilities will be calculated, and by what methods the associated costs will be allocated among users of the affected syst ems.
This, in turn, leads directly to the question of how the benefits of new transmission facilities should be assessed and what should be the proper role of benefits that cannot be readily quantified. It seems inevitable that some benefits can be determined only qualitatively. Transmission development could be hindered if those kinds of benefits cannot be considered, or even if they must be assigned less weight than those that are quantifiable, in the “commensurate benefits” calculus. The concern is that valuable projects might not go forward because their readily quantifiable benefits alone do not exceed their costs.
In a recent report prepared for WIRES,51 the Brattle Group described the ranges of benefits attributable to investments in transmission facilities, and discussed the extent to which those various benefits are—and are not—considered in transmission planning regimes across the country.52 The report emphasizes that assessment of potential transmission investments must consider the full range of direct and indirect benefits of new transmission, including those benefits that are difficult to quantify. The report notes in particular that “[i]ncreased system reliability, reduced emissions, or regional economic development will benefit society as a whole, . . . But these benefits may not directly reduce electricity customer bills.”53 It also observes that benefits to electricity customers will not necessarily always be merely a subset of total societal benefits of a transmission investment. Instead, there may be instances when benefits to electricity customers may be less than the economy-wide benefits.54
A table reproduced from the Brattle-WIRES Report55 identifies an impressive catalogue of potential benefits from transmission investments. (See Table 1 on page 9.)
FERC’s emphasis in Order No. 1000 on the “commensurate benefits” test clearly invites transmission planners and other stakeholders to explore the full range of potential benefits identified in the Brattle-WIRES Report. The report’s authors point out that production cost savings and reliability benefits are commonly considered in current transmission planning studies, and some of the other benefits they identify are now evaluated to various degrees in some RTO/ISO planning processes. Many of those categories of benefits, however, are not currently assessed even qualitatively, much less quantified, in regional planning analyses in RTO/ISO regions or non-RTO/ISO areas.56
The potential for controversies that may delay or even undermine important regional and interregional transmission projects is manifest. If approaches to benefits analysis like those described in the Brattle-WIRES Report are used, it seems inevitable that some projects will proceed based in part on benefits that cannot be quantified. Both the extent of those benefits, as well as the valuation of others that can be quantified (e.g., the insurance value of additional or higher-voltage facilities) are sure to be disputed in at least some cases. The problem could be particularly acute in interregional planning and outside RTO/ISO areas.
For practitioners, one of the key questions will be whether the legal standard of “roughly commensurate benefits” will accommodate cost allocation decisions that are based in part on qualitative analysis of benefits and the attribution of those benefits to particular customers or service areas. One can also foresee a disputed project presenting the issue of whether FERC can review (and, if so, whether it will review) and potentially overturn a regional or interregional planning decision to reject a project on the ground that its benefits were too narrowly defined and assessed. Avoiding such litigation over assumptions and valuations was one of the reasons FERC cited in defense of the orders the ICC court overturned.57 Though the court pointed out that the record on which FERC then relied contained no evidence of such disputes, its ruling nevertheless arguably could lead to fulfillment of FERC’s prediction. That outcome would not enhance the regulatory climate for transmission investment.
Order No. 1000’s abolition of ROFRs for incumbents in FERC-jurisdictional tariffs creates additional uncertainty that new transmission projects will have to overcome. In part, that is due to appeals that present significant challenges to FERC’s authority to promulgate the ban on ROFRs. Beyond that, however, there is a fundamental tension between Order No. 1000’s collaborative planning ideal and its reliance on competitive processes to execute some transmission projects—potentially including the long-distance, interregional facilities that are most important to large-scale reliance on renewable generation resources. The latter makes competitors of every adjacent utility, including any merchant transmission subsidiary any of them may elect to establish. It will be interesting to see whether FERC’s notion of such collaborative planning among competitors comes to fruition—and whether there will be antitrust challenges when selections of regional projects are made from among competing proposals, particularly in non-RTO/ISO regions. The ultimate irony, of course, would be that these two elements of Order No. 1000 turn out to work against each other, with the result of slowing transmission development even in the RTO/ISO regions where regional planning seemingly was most advanced before FERC issued the order.
Return on Equity: A Threat to Investments?
Yet another regulatory factor that presents risks for investment in the grid is the growing number of complaints filed with FERC seeking to reduce the current rates of return on equity (ROE) in utilities’ transmission service rates. There are now no fewer than 12 pending complaints and other cases at FERC involving demands for reductions in the currently authorized ROEs for individual utilities or for some or all of the transmission-owning members of an RTO or ISO.58 The most recent of the complaints was filed in November 2013, and asks FERC to cut the base ROE for the transmission owners in MISO by more than 300 basis points, from 12.38 percent to 9.15 percent.59
The allowed rate of return is not the only factor in deciding whether to invest in transmission assets, of course. Nevertheless, it is to be expected that traditional utilities, as well as the independent, transmission-only companies that have entered the market in recent years, will be less willing to invest in new facilities if they can earn a return of only 9 percent per year, rather than the materially higher, 10–12 percent they are currently allowed. These cases present a real dilemma for FERC. The commission clearly wants to encourage transmission investment, and has been relatively generous in the returns it has allowed, particularly to merchant transmission developers and when projects otherwise qualify for incentives under its rules implementing section 219 of the FPA.60 But the commission also historically has been adamant in refusing to depart from virtually any component of the very prescriptive discounted cash flow (DCF) model for establishing the ROE for electric utilities that it has developed through its precedents.61
The root of the problem is that FERC’s DCF model today produces ROEs that are much lower than the allowances the commission typically authorizes. Industry groups and other stakeholders advocating transmission development have been generating white papers and even petitioning FERC to take action generically to avoid the large reductions in ROEs that could occur if the agency adheres strictly to its established DCF parameters.62
FERC several years ago similarly found itself between a rock and a hard place with respect to returns for interstate natural gas pipelines, albeit then due to a shrinking number of publicly traded pipeline corporations, rather than inordinately low results from its ROE model. Its solution then was (as WIRES now advocates) to issue for public comment, and ultimately to adopt in large measure, a proposed policy statement modifying its regulatory approach.63 A similar initiative now might provide a way for the agency to escape the present conundrum presented by its preferred methodology for establishing electric utilities’ ROEs.
The pressure for new flexibility regarding ROEs is amplified by the perception of at least some stakeholders that FERC took a step backward in its 2012 revision of its policy on incentive returns for transmission investments.64 Two aspects of the revised policy are noteworthy for their potential negative effect on investors’ outlook regarding transmission projects.
The first of those elements is FERC’s conclusion that it now expects applicants for incentive returns on investment to commit to the cost of the subject project up front, so that any incentive return will apply only to the sponsor’s estimated cost. Though the agency said it will be flexible regarding how to implement this new policy wrinkle for specific projects, the change still may limit the salutary effects of any incentives that FERC may approve for new investments that qualify for consideration under section 219.
The second problematic facet of the new policy is FERC’s announcement that it will consider whether other risk mitigation provisions, such as recovery of all construction work in progress in rate base and of abandoned plant costs if a project fails, may offset the need for incentives in the authorized ROE for the project. In numerous past orders, the agency has applied the incentives policy of section 219 relatively broadly, including ROE adders in recognition of the risks of single-asset companies, for locating a project in an area of chronic congestion, for commercial deployment of new technology, and for participation in RTOs.65 The new approach indicates that project sponsors will find it more difficult to obtain such adders, and thus may rule out some potential investments that they previously might have evaluated more favorably.
Modernization of the nation’s electric transmission grid, including the expansions and upgrades that will facilitate large-scale integration of renewable generation resources, is generally accepted as an important national policy objective. FERC is directed by statute to provide incentives for transmission investment, and has embraced that obligation, albeit with some recent retrenchment. Certainly, the aspects of the commission’s regulations and precedents that this article discusses are not overtly inconsistent with the policy goal. They nevertheless present risks to the current surge of investment in the interstate grid. Stakeholders and their counsel will be well advised to understand those risks, and to do all they can to persuade FERC to ensure that its decisions regarding cost allocations, regional transmission planning, and utilities’ rates of return on equity will enhance, rather than undermine, the ongoing transformation of the transmission network.
1. Electricity Advisory Committee, Keeping the Lights On in a New World, at 50 (Jan. 2009) available at http://tinyurl.com/popqqtp. The Federal Energy Regulatory Commission (FERC) approves the establishment of RTOs and independent system operators (ISOs) by member utilities under criteria stated in its regulations. See generally Trans. Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002) (ISO criteria); Regional Transmission Organizations, Order No. 2000, 1996-2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, 1996-2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,092 (2000), pet. for rev. dismissed sub nom. Pub. Util. Dist. No. 1 v. FERC, 272 F.3d 607 (D.C. Cir. 2001) (RTO standards).
2. Under the Federal Power Act (FPA), FERC has regulatory jurisdiction over transmission and sales for resale of electric power in interstate commerce, and over the “public utilities” that own or operate facilities for such activities. See 16 U.S.C. §§ 792, et seq. (FPA, Title II, as amended).
3. Ill. Commerce Comm. v. FERC, 576 F.3d 470 (7th Cir. 2009) (“ICC”).
4. Id. at 477; in the interest of full disclosure, the author of the dissenting opinion in ICC is the editor-in-chief of this publication.
5. See, e.g., Mw. ISO Trans. Owners v. FERC, 373 F.3d 1361 (D.C. Cir. 2004); Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315 (D.C. Cir. 2004); K N Energy, Inc. v. FERC, 968 F.2d 1295 (D.C. Cir. 1992).
6. See, e.g., Desert Sw. Power, LLC, 135 FERC ¶ 61,143 (2011); Green Power Express, LP, 127 FERC ¶ 61,031 (2009).
7. ICC, 576 F.3d at 477 (citations omitted).
8. Id. at 474.
10. Id. at 474–75.
11. Id. at 477 (citation omitted).
13. Id. at 478 (citation and internal quotation marks omitted).
15. PJM Interconnection, L.L.C., 138 FERC ¶ 61,230 (2012), order on reh’g, 142 FERC ¶ 61,216 (2013).
16. Id. at Paragraph (P) 51.
17. Id. at P 53.
18. Id. at P 113.
19. Id. at P 117.
20. See, e.g., Midwest Indep. Trans. Sys. Operator, Inc., 133 FERC ¶ 61,221 (2010), order on reh’g, 137 FERC ¶ 61,074 (2011) (conditionally accepting postage stamp allocation across RTO region of portion of costs of high-voltage “multi-value projects”), aff’d in part, remanded in part sub nom., Ill. Commerce Comm. v. FERC, 721 F.3d 764 (7th Cir. 2013) (“ICC II”); Sw. Power Pool, Inc., 131 FERC ¶ 61,252 (2010), reh’g denied 137 FERC ¶ 61,075 (2011) (accepting “highway/byway” proposal that allocates all costs of transmission upgrades or expansions operating at or above 300 kV on postage stamp basis across RTO region).
21. See Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000, III FERC Stats. & Regs., Regs. Preambles ¶ 31,323 (2011) (“Order No. 1000”), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g and clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012).
22. Prior to a name change effective on April 26, 2013, MISO’s name was Midwest Independent Transmission System Operator, Inc.
23. ICC II, 721 F.3d at 774.
26. Id. (quoting Midwest Indep. Transmission Sys. Operator, Inc., 133 FERC ¶ 61,221, at P 34 (2010)).
29. Id. at 775.
30. Id. (quoting ICC, 576 F.3d at 477) (alteration in original).
31. Edison Electric Institute, Transmission Projects: At a Glance at iii (Mar. 2013), available at http://tinyurl.com/brcjhls.
32. The Brattle Group, Inc., Transmission Investment Trends and Planning Challenges, presented by J. Pfeifenberger at EEI Transmission and Wholesale Markets School (Aug. 2012), available at http://tinyurl.com/brcjhls.
33. Judy W. Chang, et al.– (The Brattle Group, Inc.), A WIRES Report on The Benefits of Electric Transmission: Identifying and Analyzing the Value of Investments, (July 2013), available at http://tinyurl.com/mxjgvl7.
34. See DSIRE, Rules, Regulations & Policies for Renewable Energy, http://tinyurl.com/nyw3ndl (last visited Dec. 10, 2013).
35. US DOE, Office of Energy Efficiency and Renewable Energy, Renewable Electricity Futures Study, Nat’l Renewable Energy Laboratory (Dec. 2012), http://www.nrel.gov/analysis/re_futures/ (follow links under “Renewable Electricity Report”) (“NREL Renewable Futures Study”).
36. Id. Vol. 4 at 29-1.
37. Id. Executive Summary at iii.
38. See Adam James and Bracken Hendricks, Thinking Big: NREL Study Shows 80 Percent Renewables Possible By 2050, Climate Progress, (June 27, 2012, 4:07pm), http://tinyurl.com/7cwsmdc. Notably, NREL assumed that all existing facilities would remain in service for its entire study period. NREL Renewable Futures Study, Executive Summary, xl n.34. Thus, the referenced estimates of capital costs presumably do not include investment that will be required to maintain reliability and to replace facilities that reach the end of their useful lives.
39. NREL Renewable Futures Study, Vol. 4 at 27-22. See also Brattle WIRES Report at 7 (same).
40. John Jimison & Bill White, Transmission Policy: Planning for and Investing in Wires, America’s Power Plan 7 (2013), http://tinyurl.com/7cwsmdc (footnotes omitted).
41. Supra n. 21.
42. Sandra Ringelstetter Ennis with James Heidell, FERC Order 1000 & Public Policy Transmission Projects, NERA Econ. Consulting, 1 (March 5, 2012), http://tinyurl.com/n6odmo4.
43. Though FERC will review and approve all regional planning processes, the regional plans those processes produce will not be filed with the commission. However, an entity that wishes to contest the procedures or outcome of a regional plan presumably may do so by filing a complaint under section 206 of the FPA and FERC’s rules thereunder.
44. See, e.g., Order No. 1000 at P 68.
45. See id. at P 2.
46. Id. at P 160. See also Duke Energy Carolinas LLC, 142 FERC ¶ 61,130 (2013) (rejecting proposed regional planning structure encompassing only the service areas of the operating utilities of two newly merged utility holding companies).
47. FERC’s prohibition does not reach local projects, i.e., those that are located wholly within a utility’s retail service area.
48. Order No. 1000 at P 586.
49. See ICC, 576 F.3d at 477.
50. Order No. 1000 at PP 585–86.
51. WIRES is the Working group for Investment in Reliable and Economic electric Systems. It describes itself as “a non-profit working group and the voice of electric transmission owners, investors, and customers in the North American energy market.” The group’s members are identified at http://wiresgroup.com/ourmembers.html.
52. Brattle-WIRES Report, Executive Summary at i.
53. Id. at 18.
55. Id. at 10.
56. Id. at 30, 32.
57. See, ICC, 576 F.3d at 474.
58. See, e.g., ENE, et al. v. Bangor Hydro-Electric Co., et al., Complaint, Docket No. EL13-33-000 (Dec. 27, 2012) (seeking order reducing current ROE of 11.14 percent to 8.7 percent); New York Ass’n of Public Power v. Niagara Mohawk Power Corp., et al. Complaint, Docket No. EL12-101-000 (Sept. 11, 2012) (seeking order reducing current ROE of 11 percent to 8.99 percent); Seminole Elec. Coop., Inc., et al. v. Florida Power Corp., Complaint, Docket No. EL12-39-000 (Feb. 29, 2012) (seeking order reducing current ROE of 10.8 percent to 9.02 percent).
59. See Ass’n of Businesses Advocating Tariff Equity, et al. v. MidContinent Indep. Sys. Operator, Inc., et al., Complaint, Docket No. EL14-12-000 (Nov. 12, 2013). A few transmission owners in MISO have ROEs higher than the base ROE due to adders for independent ownership and other factors; the complaint seeks to lower those owners’ ROEs to 9.15 percent also.
60. 16 U.S.C. § 824s (requiring FERC to establish “incentive-based (including performance-based) rate treatments” for jurisdictional transmission, including, inter alia, “return on equity that attracts new investment in transmission facilities.” See Promoting Transmission Investment Through Pricing Reform, Order No. 679, 2006-2007 FERC Stats. & Regs., Regs. Preambles ¶ 31,222, order on reh’g, Order No. 679-A, 2006-2007 FERC Stats. & Regs., Regs. Preambles ¶ 31,236 (2006), order on reh’g, Order No. 679-B, 119 FERC ¶ 61,062 (2007) (promulgating regulations to implement FPA section 219).
61. See, e.g., Pac. Gas & Elec. Co., 141 FERC ¶ 61,168 (2012) (requiring utility to re-file its proposed base ROE to conform to FERC’s methodology).
62. See Edison Electric Inst., Transmission Investment: Adequate Returns and Regulatory Certainty Are Key (June 2013), available at http://tinyurl.com/lanclp4; WIRES, Petition for Statement of Policy, FERC Docket No. RM13-18-000 (June 26, 2013), available at http://tinyurl.com/kvups4a.
63. See Composition of Proxy Groups for Determining Gas and Oil Pipeline Return on Equity, 123 FERC ¶ 61,048 (2008).
64. Promoting Transmission Investment Through Pricing Reform, 141 FERC ¶ 61,129 (2012); David Raskin, Transmission Policy in Flux, Pub. Util. Fortnightly (May 2013) (asserting that “whether by design or not, FERC has now created a disconnect with the pro-transmission investment policy that it (and Congress) have so earnestly favored.”); Kurt Strunk, Julia Sullivan, FERC’s U-Turn on Transmission Rate Incentives, Feb. 15, 2013, available at http://tinyurl.com/lwk6qud.
65. See, e.g., N. Pass Transmission LLC, 134 FERC ¶ 61,095 (2011); RITELine Ill., LLC, 137 FERC ¶ 61,039 (2011); Desert Sw. Power, LLC, 135 FERC ¶ 61,143 (2011).