Docket No. RM21-17-000

The Final Rule Is a Pretext for Enacting a Sweeping Policy Agenda Never Passed by Congress, Denies the States the Authority Promised by the NOPR, and Fails the Commission’s Consumer Protection Duty under the Federal Power Act

The Federal Power Act (FPA) is, at its core, a consumer protection statute.[1]  In FPA section 206, which today’s final rule purports to be based on, Congress explicitly directed this Commission to protect consumers from public utility “rates” that are “unjust, unreasonable, unduly discriminatory or preferential.”[2]  This final rule, however, fails to fulfill the Commission’s consumer protection duty required by the statute.  The final rule should be seen for what it is:  a pretext to enact, through administrative action, a sweeping legislative and policy agenda that Congress never passed.[3]  The final rule claims statutory authority the Commission does not have to issue an absurdly complex bureaucratic blizzard of mandates and micromanagement[4] to be imposed on every transmission provider in the United States for the transparent goal of spending trillions of consumers’ dollars on transmission not to serve consumers in accordance with the FPA, but instead to serve political, corporate, and other special-interest agendas that were never enacted into law.[5]  The rates for transmission that will result from the final rule will not only be unjust, unreasonable, unduly discriminatory and preferential, but grossly unfair to tens of millions of American consumers already burdened with rapidly growing monthly power bills.   

The fundamental principle historically embedded in utility regulation in the United States is to provide consumers with reliable power at the least cost under applicable law.  This principle is fair and compelling because the vast majority of American utility consumers are captive customers who pay a monopoly utility for a vital public service—electrical power—which no one can live without in modern society.  Transmission is an essential component of this vital public service,[6] so necessary transmission must be built.

Today’s final rule, however, is not about providing reliable power to consumers at least cost through just and reasonable rates as required by the FPA, despite the final rule’s claim.  And it is certainly not about being fair.  On the contrary, the final rule inflicts staggering costs on consumers by promoting the construction of trillions of dollars of transmission projects,[7] not to serve consumers in accordance with the FPA, but to serve a major policy agenda never passed by Congress, to serve the profit-making interests of developers of politically preferred generation, primarily wind and solar, and to serve corporate “green energy” preferential purchasing policies.[8]  As such, the final rule does not deserve a shred of deference under Chevron U.S.A., Inc. v. Natural Resources Defense Council, Inc.[9] in any form.  Today’s final rule is much less the product of reasoned decision-making or the agency’s specialized expertise, as of political pressure and special interest lobbying. [10]  In the chapter on “regulatory capture”[11] in future economics textbooks, today’s final rule should be a featured case study.

The final rule orders all transmission providers, RTO and non-RTO, to plan costly regional transmission for some allegedly predictable generation mix 20 years in the future (a generation mix which, as a practical matter, is impossible to predict so far into the future).[12]  The obviously pretextual agenda of the final rule, however, is not to predict the generation mix 20 years forward, but to produce the preferred generation mix that the current presidential administration, some huge multinational corporations,[13] some members of Congress, and other special interests want nowIn fact, the final rule is not even about planning transmission, but is about planning policy, and it is very preferential about the policies it wants to promote.  As with the Great Oz,[14] pulling back the curtain exposes the final rule for what it really is:  An essential component in a comprehensive plan by the current presidential administration to push what the media describe as “green policies” designed to prefer and promote the wind and solar generation it favors while simultaneously forcing the shutdown of the fossil fuel generation it disfavors,[15] both needed to meet its political commitment.  Let me emphasize:  Whether the policies being promoted in this final rule can be described as “green, purple, red or blue” is irrelevant.  The point is that FERC, as an independent agency, has no business promoting the policies of any one party or presidential administration, especially when, as here, the effort to do so goes far beyond FERC’s legal authority and fails to perform our consumer protection function under the FPA.

Yet here’s the legal rub with the final rule’s pretextual agenda:  Congress never voted to amend the FPA to direct or even allow FERC (which is supposed to be independent) to be what Energy Secretary Granholm describes as one of “our partners across the administration” in implementing this “green energy” transformation agenda.[16]  Such a sweeping policy agenda, which involves the transfer of literally trillions of dollars of wealth from consumers to special interests, is the epitome of a major question of public policy under West Virginia v. EPA.  The final rule clearly intends to socialize trillions of dollars of costs for the transmission necessary to pursue this transformational agenda, and unlike the NOPR,[17] the final rule removes the principle that the states must consent to how and whether these massive costs are imposed on their consumers.  The final rule goes to great lengths to use “nothing to see here” rhetoric,[18] but looking behind the curtain at what is really going on makes it obvious that the final rule is pretextual and a blatant violation of the major questions doctrine.[19]  In its transparent effort to plan and fund trillions of dollars’ worth of transmission to facilitate a preferred generation mix predominantly of wind and solar, both for public policies as well as corporate purchasing preferences, it is also “preferential” and thus a clear violation of FPA section 206.

Put most simply, the final rule is a shell game that plays this way: 

Step One:  For planning and cost allocation purposes, throw transmission projects that solve specific reliability problems or reduce congestion costs into the same bucket as projects designed to promote public policies or corporate “green energy” preferences and disguise the purpose of very different projects by re-labeling all projects in the new bucket with the innocuous-sounding name “Long-Term Regional Transmission Facilities.”

Step Two:  Mandate planning inputs that must be used in determining which projects get selected for regional plans, which starts the money flowing from consumers to developers before any state has even evaluated the need for, or cost of, the projects. 

Step Three:  Mandate benefits that will ultimately affect the allocation of costs to consumers across a multi-state region.  Combined with Steps One and Two, this makes consumers involuntary “beneficiaries” who will then be forced to pay for projects that promote another state’s public policy or corporate “green power” commitments. 

Step Four:  Order all transmission providers to develop and file a cost allocation formula that will automatically be the default applicable to the entire bucket of Long-Term Regional Transmission Facilities. 

Step Five:  Remove the NOPR’s requirement that states must consent to the details of Steps One through Four before their consumers can be burdened with costs.

Let’s drill down on the details of the final rule’s shell game.  The final rule seeks to shift the costs of transmission projects whose purpose is to implement state or local public policies promoting wind and solar generation (commonly referred to as “public policy projects” or “policy-driven projects”) and big corporation “green energy” preferences by putting those projects into the same regulatory bucket—both for planning and cost-allocation purposes—with fundamentally different types of projects, those designed either to solve identified reliability problems (an engineering purpose, not a political or corporate purpose) or to provide quantifiable congestion cost savings (economic projects).[20]  The final rule labels all projects thrown into the new bucket as “Long-Term Regional Transmission Facilities.”[21]  Lumping policy-driven projects with the other very different types of projects is a sleight-of-hand move to disguise the costs of the policy-driven and corporate-driven projects that the final rule is promoting.[22]  Put most simply, reliability projects are driven by engineering, economic projects by economics, public policy projects by politicians, and corporate “green energy” policies by management and investors looking to maximize their returns or satisfy investment goals not recognized by the FPA.

Then to further promote its preferred policy projects, the final rule mandates planning criteria to be used in the planning of Long-Term Regional Transmission Facilities,[23] including the “categories of factors” that must be used in developing long-term planning scenarios[24] and the list of benefits that must be used by planners in cost-benefit analyses.[25]  All of these mandatory features are transparently intended to “pre-cook” outcomes by manipulating the planning and evaluations that determine which projects are selected for regional transmission plans.  (It is emblematic of the entire final rule that it did not include “saves retail customers money” as one of its mandatory benefits for evaluating projects.)[26]  The shell game’s purpose is to ensure that preferential policy and corporate-driven projects are selected for regional transmission plans, which conveniently ensures that such projects are eligible for cost recovery through FERC’s very generous (to developers, not consumers) formula rate mechanism.  As further proof of the nature of the shell game, the final rule does not require transmission providers to identify the benefits used (other than those mandated), or how those benefits were specifically calculated, for cost allocation purposes.[27]  While the final rule insists that it is not mandating outcomes, when you manipulate the inputs of transmission planning, you are effectively mandating outputs.[28] 

But that’s not all; here comes the worst part of the shell game.  The final rule then requires every transmission provider in America to file an ex ante cost allocation formula that is applicable to the whole bucket of projects,[29] which now includes public and corporate-driven policy projects, in order to socialize the costs of these projects across the entire region, even when states in a region have never consented for their consumers to bear the costs of such projects.  The final rule seeks to justify this imposition of costs on non-consenting states by treating their consumers as “cost causers” or “beneficiaries,”[30] which is justified by—now circle back to earlier in the shell game—the final rule’s imposition of mandatory factors and benefits that must be used in the evaluations of projects.[31]  By lumping reliability and economic projects into the same planning bucket as public and corporate-driven policy projects, the final rule seeks to affix the tags of “cost causer” and “beneficiary” to all consumers in a multi-state region, to justify sticking them with costs even if their state officials never consented.  So despite the final rule’s disingenuous claims to the contrary,[32] the intent and effect of this shell game is to enable the costs of corporate and public policy-driven projects to be socialized across an entire multi-state region and thus shifted onto consumers in states that never agreed to bear such costs.  The explicit promise of the NOPR, that states would have to consent for their consumers to bear such costs, has been broken in this final rule.

When I voted for the NOPR, I made it absolutely clear I was voting for it because it reflected a compromise in which public and corporate policy-driven projects could be incorporated into long-term planning, but only if the states had the authority to consent both to planning criteria, including benefits used in cost-benefit analyses to evaluate projects and selection criteria, as well as to cost allocation.[33]  In my concurrence to the NOPR I wrote:

Even more importantly though, for these [long-term] projects, the NOPR proposes to require the regional planning entities to consult with and seek the agreement of the relevant states to both the selection criteria for these projects and to the regional cost allocation arrangements.  State approval is especially important in a multi-state region, where different states have different policies.  The NOPR proposes to provide the maximum opportunity for creativity and flexibility to the states and regional entities in developing the process for designing and approving regional selection criteria and cost allocation arrangements.  States can agree to an ex ante formula for regional cost allocation of these types of projects — such as, for example, the “highway-byway” formula approved by the SPP Regional State Committee — or states can agree to a process for a project-by-project agreement on cost allocation among one or several states — such as, for example, the State Agreement Approach in PJM — or states may choose some combination of both.[34]  

And let me emphasize . . . no individual state’s consumers can be forced to bear the costs of another state’s policy-driven project or element of a project against its consent.[35]

The bottom line for me is this:  I believe that elevating the role in planning and cost allocation of state regulators — who are, as a group, deeply concerned about the monthly bills paid by consumers, of which transmission is a rapidly growing component — will make it more likely, not less, that necessary transmission can get built while ensuring that rates resulting from these types of policy-driven projects will not be unjust and unreasonable, which they clearly have the potential to be.[36]

The other members of the Commission, including the then-Chairman and both other members of today’s Commission, also recognized the NOPR as a compromise.[37]  

Yet the many fundamental changes made in this final rule[38] subvert and violate that compromise.  Of particular importance to my willingness—and that of many state regulator organizations—to support the compromise NOPR, was the explicit principle of state agreement to planning and selection criteria and cost allocation embodied in the NOPR.  The final rule, however, denies what the NOPR promised:  it denies state agreement to selection criteria,[39] it denies state agreement to the benefits to be used in evaluating projects for selection in regional plans and ultimate selection (which can start the money flowing from consumers to developers before a state siting or construction permit has even been issued),[40] and most importantly, it denies state agreement to cost allocation for public policy and corporate-driven projects.[41]  The State Agreement Approach, used successfully in PJM for over a decade, is effectively terminated by the final rule.  The final rule says that, even if states in a planning region agree, a “State Agreement Process” cannot be the sole chosen method for allocating costs of these projects; the transmission provider’s own ex ante formula must be the default method, regardless of whether states have agreed to it.[42]  In addition to a de facto termination of the PJM State Agreement Approach, the final rule could call into question mechanisms to facilitate the states’ role in cost allocation that have been used in other RTOs and ISOs for years, including in SPP and MISO.[43]

And let’s get real:  Telling the states to negotiate for an alternative cost allocation when the transmission provider’s ex ante formula has already been designated as the default is no real negotiation at all.  The final rule points a regulatory gun at states’ heads redolent of The Godfather:[44]  “Here’s an offer you can’t refuse.”  And contrary to NARUC’s eminently reasonable and practical request,[45] the final rule even requires only one Engagement Period for states to negotiate a different cost allocation from the transmission providers’ ex ante cost allocation before that ex ante cost allocation becomes the default.[46]  It is obvious that the final rule intends to lock in each transmission provider’s own ex ante formula for many years to come and to deny states any avenue to challenge it even as times and circumstances change, no matter how high their consumers’ power bills escalate due to rising transmission costs. 

Essentially, the final rule replaces the NOPR’s principle of requiring state agreement to selection criteria, benefits, and cost allocation with a charade of suggesting to transmission providers that they “consult with and seek support” from the states—while paradoxically “clarifying” that transmission providers do not actually need to obtain state consent—and the final rule uses other empty phrases such as allowing states to “inform” or “provide input on” the evaluation process and cost allocation.[47]  But the final rule’s real attitude towards the states and state regulators is embodied in this airily regal but perhaps unintentionally straightforward pronouncement:  “[W]e do not agree that the views of state regulators regarding the appropriate cost allocation approach are dispositive.”[48]

The principle of cost allocation that was described in my concurrence to the NOPR—that states must consent to regional cost allocation of corporate and public policy-driven projects—reflects a core principle of American democracy:  fairness.  In this ratemaking context, fairness means that the people have the right to choose the policymakers who impose costs on them, so they can hold them accountable.  This final rule is unfair because it gives FERC and the transmission providers it regulates the power to impose costs on consumers to pay for transmission driven by huge corporations and politicians in states other than theirs, and for whom they never voted.  The final rule truly subverts the principle that the people, through their state’s policymakers, must consent to bear the costs of another state’s politicians and their policy choices, or the energy purchasing preferences of corporate managers and investors. 

And from the consumer standpoint, the timing of this rule could not be worse.  American residential customers will pay about 16.23 cents per kWh next year, the highest retail power cost for consumers in almost three decades.[49]  Unlike in years past, fuel costs are not the primary driver of these mounting prices to consumers; rather, transmission is.  Transmission costs are rising rapidly, becoming an ever more burdensome part of consumers’ power bills.[50]  To cite just one major example, in PJM, the largest RTO by load in the country, the transmission component of wholesale power costs has essentially tripled over the past decade, from just $5.65/MWh in 2013 to $16.54/MWh last year.  Transmission now constitutes almost a third of wholesale power costs, up from approximately 10% just a decade earlier.[51]  In 2020, the PJM Market Monitor reported that the cost of transmission exceeded the cost of capacity for the first time.[52]  Nationally, transmission rate base nearly tripled in a decade,[53] and—assuming an 8.2% year-over-year growth rate, which occurred in 2022—is on track to double again in the next nine years, even without this rule’s intent to spend trillions more on transmission.  According to the U.S. Energy Information Administration, already one in three American households reports difficulty in paying their power bills.[54]

Don’t fall for the absurd claim that this rule will somehow save consumers money through more holistic or efficient planning, a vacuous bureaucratic argument divorced from reality.[55]  The sheer amount of new transmission costs that the final rule inflicts on consumers—and special interest groups want—is staggering, measured in the trillions,[56] not ‘merely’ hundreds of billions, of dollars.[57]  And these staggering costs will not be incurred to provide consumers with reliable power, but to serve political and corporate agendas.  It is truly Orwellian newspeak[58] to claim that adding multiple trillions of dollars in transmission costs to consumer’s bills will somehow “save” consumers money (even Orwell would be impressed at the sheer audacity of such a claim).

If FERC were seriously interested in saving consumers’ money, it would be acting to rein in the wide array of transmission incentives regularly handed out to transmission developers that are direct transfers of wealth from consumers to developers (long known as “FERC candy”),[59] and acting to reform the automatic awarding of the presumption of prudence in formula rate proceedings.  Literally nothing is being done about these forms of consumer exploitation in this final rule; instead, the final rule goes in the exact opposite direction.

To add further insult to consumers’ injury, the final rule walks back the NOPR proposal that would have denied transmission developers the Construction Work in Progress (CWIP) incentive.[60]  I have written many times that CWIP is simply unfair.  CWIP is unfair because it makes consumers the unwilling “bank” for developers, but unlike a real bank, consumers don’t get paid any interest and this Commission forces them to make involuntary loans.[61]  Removing CWIP was strongly supported by those concerned with protecting consumers:  by state regulators, by public power providers, and by state consumer advocates.

In my concurrence to the NOPR, I wrote:

CWIP is the award of cost recovery of construction costs during the pre-construction and construction phases to the developer.  CWIP is, of course, passed through as a cost to consumers, making consumers effectively an involuntary lender to the developer. . . .  Consumers should be protected from paying CWIP costs during this potentially long period before a project actually enters service, if it ever does.  This NOPR proposal represents a major step forward in consumer protection and is a big reason I am voting for it.[62]

By walking back the proposed CWIP denial, the final rule results in a major step backwards for consumers.[63]

In yet another major slap at consumers, the final rule seeks to shift the substantial costs caused by generation developers’ interconnection requests from developers to consumers.[64]  It does this by ordering transmission providers to revise their regional transmission planning processes to evaluate for selection regional transmission facilities that address identified interconnection-related transmission needs, and the final rule specifies that if such a facility is selected, its costs will be regionally allocated.[65]  It also does this by ordering transmission providers to incorporate generator interconnection requests and withdrawals in their long-term transmission planning.[66]  These are only schemes to shift interconnection costs from developers to consumers and will result in rates that are blatantly unjust, unreasonable, unduly discriminatory and preferential.  Similarly, the final rule also inappropriately shifts preferential corporate-driven project costs onto all other consumers, who may disagree with, or even compete against, the corporate customers imposing their preferences.  These provisions alone render the final rule’s replacement rate unlawful under FPA section 206.

This Commission is, by statute, supposed to be independent of any presidential administration, but it has failed to defend that independence in this final rule, which is a naked pretext to enact the current administration’s “net zero 2035” policy agenda, as well as to serve corporate agendas, and those of other profit-seeking special interests.[67]  In failing to act independently,[68] this Commission has broken faith with state regulators and, even more importantly, broken faith with tens of millions of American consumers, who could be forced to bear literally trillions of dollars in costs for transmission lines to serve political, corporate and other special-interest agendas.  This will not produce just and reasonable rates and is grossly unfair.  This final rule is a dereliction of the Commission’s duty under the FPA to protect consumers and far exceeds its authority under that statute.

The Final Rule Is Fundamentally Different from the NOPR

The very essence of due process is notice and opportunity to be heard.  Given the large number of fundamental changes to the NOPR, the final rule should be viewed as effectively a second NOPR and clearly should have been put out for additional public comment on the many fundamental changes.  Because it was not, deliberately so, this final rule invites a court to remand with instructions for the Commission to give the public an opportunity to comment on the many fundamental changes from the NOPR.

The final rule issuing today is not the NOPR for which I voted.  This pretextual final rule is fundamentally different in numerous ways, yet these fundamental changes were never put out for additional public comment.[69]  These fundamental changes include, but are not limited to, the following:

The Final Rule Imposes Preferential Policy and Corporate-Driven Project Costs on Consumers in Non-Consenting States:  Contrary to the NOPR, the final rule requires the filing of one or more ex ante cost allocation methods to apply to selected Long-Term Regional Transmission Facilities, setting up a mechanism to impose a regional cost allocation for preferential policy and corporate-driven projects when states do not consent, either by approving a cost allocation proposed by transmission owners, by RTOs, or one directly imposed by the Commission itself.[70]  This is a fundamental change from the NOPR. 

The Final Rule Mandates Planning Criteria and Purported Benefits:  Contrary to the NOPR, the final rule mandates a specific set of planning criteria, and specifically purported benefits, that must be used by transmission providers for these preferential policy and corporate-driven projects.[71]  Mandating the planning criteria and benefits is simply a way of “pre-cooking” outcomes and is directly contrary to the NOPR’s explicit language that said it was not mandating outcomes, only a planning process.[72]  This is a fundamental change from the NOPR.

The Final Rule Abandons Regional Cost Allocation Principle (6):  Contrary to the NOPR,[73] the final rule abandons the regional cost allocation principle[74] that would allow a transmission planning region to use different cost allocation methods for different types of facilities in a regional transmission plan.  The final rule replaces this flexibility with a one-size-fits-all model.[75]  This is a fundamental change from the NOPR.

The Final Rule Effectively Eliminates a Voluntary State Agreement Process:  Contrary to the NOPR, the final rule effectively eliminates the use of a voluntary State Agreement Process, such as the one that has been used by PJM since Order No. 1000.[76]  Not only is this directly contrary to comments filed by state regulators,[77] but it represents a fundamental change from the NOPR.

The Final Rule Leaves the CWIP Incentive Intact:  Contrary to the NOPR, the final rule walks back the proposal not to allow use of the CWIP incentive.[78]  This NOPR provision was one of the strongest consumer protection features.[79]  Instead, the Commission leaves the CWIP incentive intact and that consumer protection has been removed.  This is a fundamental change from the NOPR.

The Final Rule Makes Local Transmission Planning Less Transparent:  Contrary to the NOPR,[80] the final rule makes fundamental changes to the NOPR’s section on Local Transmission Planning.[81]  Local Transmission Planning disclosure and transparency requirements no longer apply to asset management projects.  This is a fundamental change from the NOPR.

The Final Rule Exceeds FERC’s Authority under the FPA

The final rule’s determination that its reforms are within the Commission’s legal authority under section 206 is flat wrong.[82]  The final rule is just a pretext for enacting the current presidential administration’s “net zero 2035” policy agenda, as well as that of large corporate buyers of preferential power and other special interests. [83]  As such, the final rule goes far beyond the scope of Order No. 1000, as affirmed by South Carolina,[84] and exceeds FERC’s authority under the FPA.  Specifically, the final rule requires transmission providers to incorporate into their transmission planning seven categories of factors and a set of seven required benefits to drive the construction of projects to achieve the final rule’s preferred substantive outcomes:  namely, the development and purchase of certain preferred generation resources.  In so doing, the final rule seeks to recast FERC as a national IRP planner with extraordinary powers to oversee and dictate to all public utility transmission providers in the country, in RTO and non-RTO regions, detailed instructions on planning transmission that fulfills the current administration’s preferred policies as to the types of generation it wants to build, and to charge consumers trillions of dollars for this transmission.  This transformation of FERC into a national IRP planner violates FPA section 201 by infringing on the authority of the states, and it reflects a tremendous expansion of the agency’s power not permitted under the major questions doctrine.

South Carolina Does Not Provide a Legal Justification for the Commission’s Actions in the Final Rule

In arguing that the Commission is acting within its legal authority under section 206 to adopt its reforms for Long-Term Regional Transmission Planning, today’s final rule heavily relies on South Carolina.[85]  However, given the significant differences between Order No. 1000 and the final rule, that reliance is grossly misplaced.  

Order No. 1000 included reforms intended to ensure that the transmission planning and cost allocation requirements embodied in the Commission’s pro forma open access transmission tariff could support the development of more efficient or cost-effective transmission facilities.[86]  Such reforms included, inter alia, the requirement for transmission providers to participate in regional planning processes; the requirement that such regional transmission planning processes must consider transmission needs that are driven by public policy requirements; and the requirement that transmission providers develop a regional cost allocation method for new transmission facilities selected in the regional transmission plan for purposes of cost allocation, with such method having to satisfy six regional cost allocation principles. 

But Order No. 1000 was built on what may be a foundation of sand known as “Chevron deference.”  As the D.C. Circuit explained in South Carolina, “[t]he court reviews challenges to the Commission’s interpretation of the FPA under the familiar two-step framework of [Chevron].”[87]  The D.C. Circuit further explained that, “[i]f the court determines ‘Congress has directly spoken to the precise question at issue,’ and ‘the intent of Congress is clear, that is the end of the matter.’”[88]  This is often referred to as “Chevron step one.”[89]  The court stated, in contrast, that “[i]f . . . ‘the statute is silent or ambiguous with respect to the specific issue,’ then the court must determine ‘whether the agency’s answer is based on a permissible construction of the statute.’”[90]  This is often referred to as “Chevron step two.”[91]  The D.C. Circuit explained that “Chevron step two . . . requires [the court] to uphold an agency’s reasonable interpretation of a statute it administers.”[92]  That is, the court applies Chevron deference.[93]

In South Carolina, the D.C. Circuit applied Chevron deference to the Commission’s interpretation of FPA section 206 in affirming many aspects of Order No. 1000, including its planning mandates.[94]  In affirming the planning mandates, the court emphasized that Order No. 1000 focused on process and not substantive outcomes:

In Order No. 1000, the Commission expressly “decline[d] to impose obligations to build or mandatory processes to obtain commitments to construct transmission facilities in the regional transmission plan.”  More generally, the Commission disavowed that it was purporting to “determine what needs to be built, where it needs to be built, and who needs to build it.” As the Commission explained on rehearing, “Order No. 1000’s transmission planning reforms are concerned with process” and “are not intended to dictate substantive outcomes.  The substance of a regional transmission plan and any subsequent formation of agreements to construct or operate regional transmission facilities remain within the discretion of the decision-makers in each planning region.[95]

Similarly, in determining that Order No. 1000’s public policy mandate fell within the Commission’s authority under section 206, the D.C. Circuit noted the mandate did not promote any particular public policy:

[Petitioners] seem to argue that the Commission can only exercise authority to promote goals specified in the FPA and that the public policy mandate cannot be justified with respect to any of those goals.  This argument misunderstands the nature of the mandate.  It does not promote any particular public policy or even the public welfare generally.  The mandate simply recognizes that state and federal policies might affect the transmission market and directs transmission providers to consider that impact in their planning decisions. . . .   This fits comfortably within the Commission’s authority under Section 206. . . .  [T]he public policy mandate bears directly on the provision of transmission service.[96]

Just as with Order No. 1000’s planning mandates, the court again emphasized Order No. 1000’s public policy mandate required the establishment of processes:

But petitioners’ attack is once again based on a misunderstanding of the orders.  The orders merely require regions to establish processes for identifying and evaluating public policies that might affect transmission needs.  The regions are free to choose their own manner of determining how best to identify and accommodate these policies.[97]

Finally, in affirming Order No. 1000’s requirements pertaining to cost allocation, the court again applied Chevron deference to its interpretation of section 206.[98]  The court noted that Order No. 1000 used a “light touch” in its cost allocation reforms:

In keeping with the overall approach of the transmission planning reforms, [Order No. 1000] uses a light touch:  it does not dictate how costs are to be allocated.  Rather, [Order No. 1000] provides for general cost allocation principles and leaves the details to transmission providers to determine in the planning processes.[99]

While Order No. 1000 used a “light touch,” this pretextual final rule is heavy handed.  To ensure that policy and corporate-driven projects are ultimately built so that the preferred generation is built, the final rule seeks to promote particular public policies and to dictate substantive outcomes through its reforms to the Commission’s transmission planning and cost allocation processes.[100]  If Order No. 1000 was upheld precisely because it was only mandating processes, not outcomes, then this final rule cannot stand on South Carolina because it nakedly intends to produce very specific outcomes. 

How does it intend to do this?  First, in contrast to Order No. 1000, which mandated consideration of public policies in transmission planning but not a particular policy,[101] the final rule requires transmission providers in their Long-Term Regional Transmission Planning to incorporate seven categories of factors—i.e., specific policies, as I have emphasized.  Most of these mandatory categories of factors, which drive long-term transmission planning, specifically relate to the development and purchase of “green energy,” including, inter alia:  (i) state and local laws affecting the resource mix, (ii) state and local laws on decarbonization, (iii) generator interconnection requests and withdrawals,[102] and (iv) corporate, state and local government commitments to purchase “green energy.

The final rule describes the relationship between the categories of factors, transmission needs, and benefits, among other terms:

For purposes of this final rule, Long-Term Regional Transmission Planning means regional transmission planning on a sufficiently long-term, forward-looking, and comprehensive basis to identify Long-Term Transmission Needs, identify transmission facilities that meet such needs, measure the benefits of those transmission facilities, and evaluate those transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation as the more efficient or cost-effective regional transmission facilities to meet Long-Term Transmission Needs. 

For purposes of this final rule, Long-Term Transmission Needs are transmission needs identified through Long-Term Regional Transmission Planning, which, as discussed in this final rule, includes running scenarios and considering the enumerated categories of factors.[103]

Thus, categories of factors clearly shape the identification of transmission needs.  Demonstrating this causal relationship, the final rule explains that “best available data inputs are data inputs that . . . reflect the list of factors that transmission providers account for in their Long-Term Scenarios,”[104] and, in turn, “Long-Term Scenarios . . . incorporate various assumptions using best available data inputs about the future electric power system . . . to identify Long-Term Transmission Needs and enable the identification and evaluation of transmission facilities to meet such transmission needs.”[105] 

And, as we know, the identification of needs leads to the identification of transmission facilities that meet such needs; the identification of transmission facilities in turn leads to the measure of the benefits associated with those facilities; and the measure of benefits informs the evaluation of those transmission facilities for potential selection in the regional transmission plan for purposes of cost allocation.  Thus, as the categories of factors are slanted toward transmission to facilitate preferred generation, the resulting output of the transmission planning process will inevitably have a similar bent.  In other words, the final rule’s mandate of the categories of factors starts the domino effect toward the final rule’s agenda, an agenda that goes far beyond Order No. 1000.

Second, in contrast to Order No. 1000, whose reforms “[were] concerned with process” and “[were] not intended to dictate substantive outcomes,”[106] the final rule requires transmission providers to measure a set of seven required benefits in their long-term transmission planning so that the pretextual agenda will be realized.  By mandating minimum benefits that the transmission providers must use to evaluate potential transmission facilities,[107] the final rule is doing the opposite of using a “light touch;” rather, the final rule is putting its thumb on the scale, seeking to dictate outcomes of the transmission planning process.  As I must continue to emphasize, by mandating benefits, the final rule makes consumers into involuntary “beneficiaries,” who, through regional cost allocation, will be forced to pay for transmission projects that support the development and purchase of preferential power.  Accordingly, as with the final rule’s mandated categories of factors, the mandatory minimum benefits serve to advance the final rule’s specific policy objectives regarding the resource mix.  Such favoritism is blatantly unduly discriminatory and preferential in contravention of section 206, and therefore, the final rule is, simply put, not entitled to Chevron deference in any form.

The Final Rule Violates FPA Section 201

The final rule also infringes on the states’ authority over electric generation reserved to them by FPA section 201 and is thus ultra vires

As relevant here, FPA section 201(b) provides:

The Commission shall have jurisdiction over all facilities for such transmission or sale of electric energy, but shall not have jurisdiction, except as specifically provided in this subchapter and subchapter III of this chapter, over facilities used for the generation of electric energy or over facilities used in local distribution or only for the transmission of electric energy in intrastate commerce, or over facilities for the transmission of electric energy consumed wholly by the transmitter.[108]

Further, section 201(a) also specifies that “such Federal regulation . . . extend[s] only to those matters which are not subject to regulation by the States.”  Courts have found that “states have broad powers under state law to direct the planning and resource decisions of utilities under their jurisdiction.  States may, for example, order utilities to build renewable generators themselves, or . . . order utilities to purchase renewable generation.”[109]  These powers are reserved to the states under section 201.

In South Carolina, the D.C. Circuit rejected the argument that section 201 prohibited Order No. 1000’s transmission planning mandate.[110]  The D.C. Circuit emphasized that “because the planning mandate relates wholly to electricity transmission, as opposed to electricity sales, it involves a subject matter over which the Commission has relatively broader authority.”[111]  The court also reasoned that “because [Order No. 1000’s] planning mandate is directed at ensuring the proper functioning of the interconnected grid spanning state lines, . . . the mandate fits comfortably within Section 201(b)’s grant of jurisdiction over ‘the transmission of electric energy in interstate commerce.’”[112]  The court thus concluded that “Section 201 [did] not preclude the Commission’s regulation of transmission planning in [Order No. 1000]” and that Order No. 1000 “[did] not interfere with the traditional state authority that is preserved by Section 201.”[113]

However, in contrast to Order No. 1000, the final rule absolutely does “interfere with the traditional state authority that is preserved by Section 201” to ensure that its preferential policy and corporate-driven projects get built.  By mandating, inter alia, categories of factors that drive the transmission planning process and by mandating minimum benefits to be used in the evaluation of potential Long-Term Regional Transmission Facilities, the final rule seeks to spur the building of transmission so as to promote a specific policy objective:  the development and purchase of preferential generation.  Accordingly, although the final rule strenuously insists that it is not mandating outcomes,[114] it is doing so by manipulating the inputs of transmission planning (i.e., “pre-cooking”).[115]  In other words, the final rule seeks to do indirectly what it may not do directly.

As I explained in my concurrence to the NOPR:

States can prefer, mandate or subsidize specific types of generation resources, but the Commission cannot use its authority over transmission to pressure, steer or require regional planning entities to act as the Commission’s agents and do indirectly what the Commission cannot do directly.  The Commission is not a national integrated resource planner. Order No. 1000, to its credit, recognized this clear delineation between federal and state authority.[116]

I also explained that “the Commission cannot impose a preference for certain types of generation nor require regional entities to plan transmission designed to prefer or facilitate one type of generation over another.”[117]  

The text of the FPA gives this Commission no authority whatsoever to act as a national IRP planner for the purpose of promoting its preferred generation resource mix.  Pulling back the curtain, that is exactly what this pretextual final rule seeks to do.  By extending FERC’s control over every public utility transmission planner in the country, RTO or non-RTO, and ordering them to plan transmission lines intended to advance preferred policy and corporate goals, the Commission is stepping into the role of national IRP planner.  FERC’s authority under the FPA is limited to matters that directly affect rates, not practices that may theoretically have some tangential, indirect effect on rates,[118] especially improper purposes such as ordering transmission planning to promote one or more states’ public policies or corporate goals as to preferred generation resources.  Congress intended FERC to be a rate regulator, not a planner of generation or transmission designed to bring about the construction of preferred types of generation.  Indeed, FPA section 215 explicitly states that FERC may not order the construction of any generation or transmission asset.[119]  FERC cannot order transmission providers to do what FERC itself has no authority to do, yet that is exactly what this final rule aims to do.

The final rule purports to order transmission planners to plan for a “predicted” generation mix in a distant future 20 years away, but the exact generation mix in 20 years is impossible to predict.[120]  The real goal of this pretextual final rule is not to try the impossible by predicting the generation mix in 20 years.  Instead, the final rule is an attempt to become a national IRP planner and bring about a preferred generation mix through transmission planning by manipulating and shaping the future generation mix the special interests supporting this final rule want now.

The final rule denies that it is infringing on state authority reserved under FPA section 201, arguing, inter alia, that it directly regulates only those practices that affect the rates for the transmission of electric energy in interstate commerce and that it is not aiming to indirectly regulate any matter reserved to the states by FPA section 201.[121]  The final rule is chock-full of “nothing to see here” rhetoric asserting that it does not seek to shape the generation resource mix, but merely responds to changes in the electric industry.[122]  “Pay no attention to the [agenda] behind the [green] curtain!”[123] the final rule insists across 1300 pages.  But it should be obvious by now that the final rule is just a pretext for enacting this administration’s “net zero 2035” policy agenda, as well those of corporate and other special interests.[124]  The true intent of the final rule is revealed by mandated categories of factors and minimum benefits, which drive the transmission development necessary to achieve the final rule’s preferred generation resource mix.  Any honest account of the final rule cannot ignore the monetary windfall it would shower on generation and transmission developers; it is no wonder, therefore, why they were among the strongest supporters for the final rule.  Nor can any rational individual—unless living in the Land of Oz—reasonably deny the role the final rule plays in furthering this pretextual agenda.[125]  In light of this backdrop, the final rule’s repeated assertions that it does not seek to shape the country’s resource mix are simply not credible.  Contrary to the final rule’s claims, in violation of FPA section 201, the final rule transforms the Commission into a national IRP planner to promote the construction of transmission lines to further the development of the final rule’s preferred generation resources. 

The Final Rule Violates the Major Questions Doctrine

Courts generally look with suspicion on “cryptic” delegations of authority,[126] and they are generally skeptical of agencies that seek to find “elephants in mouseholes,” or otherwise seek to rely on tiny grants of authority to justify major actions.[127]  As the Supreme Court explained in West Virginia v. EPA:

Where the statute at issue is one that confers authority upon an administrative agency, that inquiry must be “shaped, at least in some measure, by the nature of the question presented”—whether Congress in fact meant to confer the power the agency has asserted.  In the ordinary case, that context has no great effect on the appropriate analysis. Nonetheless, our precedent teaches that there are “extraordinary cases” that call for a different approach—cases in which the “history and the breadth of the authority that [the agency] has asserted,” and the “economic and political significance” of that assertion, provide a “reason to hesitate before concluding that Congress” meant to confer such authority.[128]

I invoked the major questions doctrine in my dissent to the proposed changes to the Commission’s certificate policy, even before West Virgina v. EPA was handed down.  In my dissent, I wrote that:

“The federal government’s powers . . . are not general[] but limited and divided.  Not only must the federal government properly invoke a constitutionally enumerated source of authority to regulate in this area or any other, it must also act consistently with the Constitution’s separation of powers.  And when it comes to that obligation, this Court has established at least one firm rule:  ‘We expect Congress to speak clearly’ if it wishes to assign to an executive agency decisions ‘of vast economic and political significance.’  We sometimes call this the major questions doctrine.”

In short, the major questions doctrine presumes that Congress reserves major issues to itself, so unless a grant of authority to address a major issue is explicit in a statute administered by an agency, it cannot be inferred to have been granted.

. . .

Yet the Supreme Court has made it clear that broad deference to administrative agencies on major questions of public policy is not in order when statutes are lacking in any explicit statutory grant of authority.  “When much is sought from a statute, much must be shown. . . .  [B]road assertions of administrative power demand unmistakable legislative support.”[129]

The final rule’s actions clearly implicate the major questions doctrine.  If imposing a final rule intended to cost consumers literally trillions of dollars to build transmission projects designed to implement a sweeping policy agenda never passed by Congress is not a major question of public policy, then there is no such thing.[130] 

Yet the final rule brushes aside arguments that it would not withstand scrutiny under the major questions doctrine.[131]  Against these arguments, the final rule denies that its aim is to influence the generation mix;[132] asserts that it “neither transforms nor expands the Commission’s authority; it merely applies existing authority;”[133] asserts that “the differences in transmission planning required by this final rule represent differences in degree, not kind, from the Commission’s longstanding regulations;”[134] and asserts that its “incremental process improvements [from Order No. 1000], while necessary to ensure just and reasonable Commission-jurisdictional rates, do not have the ‘vast economic and political significance’ that would implicate the major questions doctrine.”[135]  None of these assertions are credible.

This final rule violates the major questions doctrine.  As discussed above, it is axiomatic that Congress has not intended for the Commission to be a national IRP planner.  On the contrary, it has left both the siting of transmission and the development of generation to the states.[136]  Yet the final rule encroaches on these traditional state prerogatives in the absence of any explicit Congressional authorization to do so.

The final rule seeks to shape specific policy outcomes by mandating categories of factors and minimum benefits.  In addition, the final rule does something else that also arguably makes it transformative.  Citing, inter alia, South Carolina, the final rule declares that the Commission has exclusive jurisdiction over regional transmission planning and cost allocation processes:

As the D.C. Circuit has recognized, regional transmission planning and cost allocation processes are practices affecting rates subject to the Commission’s exclusive jurisdiction.[137] 

In fact, the South Carolina court did not state that the Commission has exclusive jurisdiction over regional transmission planning and cost allocation.  In fact, that court noted, for example, that the Florida Public Service Commission is statutorily vested with authority to “plan[], develop[], and main[tain] . . . a coordinated electric power grid” throughout the state.[138] 

Whether the Commission can exclusively supplant the states in transmission planning and cost allocation is a major question—particularly considering the enormous breadth of the transmission grid, the importance of electricity in everyday life, and the trillions of dollars in transmission investment (read, cost increases) this final rule intends to impose on consumers.[139]  The final rule’s conclusion that regional transmission planning and cost allocation processes are subject to the Commission’s exclusive jurisdiction suggests that the Commission “occupies the field”[140] in these areas.[141]  But this is wrong.  This pretextual final rule erodes the states’ authority, which is inconsistent with the principle of cooperative federalism reflected in the FPA.  Under the major questions doctrine, absent an act of Congress, the Commission may not usurp the powers of the states in this manner.

The Final Rule Fails Under Both Prongs of FPA Section 206

I cannot support the final rule because it has been fundamentally changed from the NOPR.  In jettisoning essential components of the NOPR, the final rule has been reduced to a mere pretext for this supposedly independent Commission’s effort to implement the current administration’s “net zero 2035” policies.  It will not produce rates that are just and reasonable and not unduly discriminatory or preferential.  This final rule does not satisfy either of the requirements of FPA section 206.  Under section 206, the Commission must first find that the rate on file is no longer just and reasonable and not unduly discriminatory or preferential.  Then the Commission must find that a particular replacement rate would be just and reasonable and not unduly discriminatory or preferential.[142]  The final rule fails on both counts.

Although the current regional transmission planning processes could be improved—they are certainly not in need of the final rule’s solutions.  Even if these solutions were the only way forward to reform regional transmission planning, an act of Congress would be necessary first because the final rule is far beyond the reach of the FPA.  While the Commission might prefer a different rate, that preference alone does not make all the filed rates of every transmission provider unjust and unreasonable. 

The Final Rule Fails to Justify its Action Under Section 206

The final rule presents no justification for taking action in this proceeding against all of the filed transmission rates pursuant to FPA section 206.  The record, while consisting of thousands of pages of comments, simply does not contain substantial evidence sufficient to make a generic showing that the existing filed rates of all transmission providers are unjust, unreasonable, unduly discriminatory or preferential.[143]  In South Carolina, the D.C. Circuit explained that “the substantial evidence test” for a rulemaking proceeding “‘requires the Commission to specify the evidence on which it relied and to explain how that evidence supports the conclusion it reached.’”[144]  Here, the final rule’s “rel[iance] on ‘generic’ or ‘general’ findings of a systemic problem to support imposition of an industry-wide solution”[145] fails because it relies on cherry-picked special interest comments to support the pre-baked and pretextual findings needed to enact the administration’s preferential, and discriminatory, policy agenda as well those of corporate and other special interests. 

The Record Is Not Sufficient to Make a Generic Showing That Every Transmission Providers’ Regional Transmission Planning and Cost Allocation Processes Are Unjust, Unreasonable, and Unduly Discriminatory or Preferential

The evidence in the record that is used to support the final rule’s section 206 finding consists largely of comments from special interests that will profit from the final rule.  The final rule also signals that there has been limited regional transmission development since Order No. 1000.  This evidence should not be used to mean that every transmission provider in the country has transmission practices that are unjust and unreasonable.

The final rule declines to analyze the “justness and reasonableness of either generator interconnection processes or local transmission planning processes” in its survey of issues in regional transmission planning.[146]  The final rule identifies benefits of transmission planning.[147]  The final rule states that “transmission planning that considers both evolving reliability needs and other drivers of transmission needs more comprehensively can enable transmission providers to identify potential reliability problems and economic constraints.”[148]  The final rule states that transmission spending has increased, which turns into higher customer bills.[149]  The final rule identifies projections are necessary for growing future transmission needs, including load growth[150] and changing reliability needs.[151]  And supply is changing due to state policies, customer preferences, and utility preferences (the latter two can also be driven by state policies or by activist investor preferences).[152]

Translating FERC-speak, we are left with bland statements of the obvious:  Transmission is expensive to build; transmission spending is up; generators front a lot of the needed money; consumers eventually pay them back; lack of regional integrated planning results in piecemeal transmission construction; this is inefficient and costs consumers more.  Yet simply because a rate could be more efficient, that alone is not enough to make the filed rate unjust and unreasonable.

Many of the special interest commenters point to studies, projections, and reports that show that regional transmission planning could be done more efficiently.[153]  When we peel back the “green curtain” shrouding this final rule, however, we see that these comments are almost exclusively from self-interested entities which would gain substantially from the very Commission action that they support.[154]  Indeed, the record being used to support the section 206 finding consists of special interests who are going to profit monetarily from the final rule, including generation developers, transmission developers, and corporate purchasers of preferred power.[155]  None of these comments (individually or taken together) are sufficient to meet the high burden of proof that all transmission providers’ tariffs are unjust and unreasonable due to the profit-seeking motivations behind them.

In addition, the final rule looks back over the period following Order No. 1000 and states that regional transmission planning processes have yielded only “limited investments in regional transmission planning projects.”[156]  Let’s suppose that over the last decade a transmission developer had instead proposed massively expanding transmission while the load growth projections remained flat.  Consumers commenting on that aggressive plan would have challenged it as gold-plating.  Regulators would have rejected it as imprudent.  The so-called “limited investments” were instead a sign of responsiveness to projections made during that era.  Rather than seeing this outcome as a feature of considered ratemaking during a period of low load growth, the final rule attributes this lack of investment to the shortcomings of the existing regional transmission planning processes—meaning the tariff changes mandated by Order No. 1000.[157]  For these reasons, the final rule’s reliance on a lack of regional transmission development post-Order No. 1000 is not persuasive, especially to support the finding that all transmission providers’ tariffs are unjust and unreasonable.

The Record Shows That Regional Planning Deficiencies Exist Only in Isolated Pockets

The evidence in this record does not demonstrate a single nationwide systemic problem.  Rather, the record shows that the “deficiencies identified by the Commission ‘exist[] only in isolated pockets.’”[158]  The final rule even recognizes the many regions representing a substantial percentage of consumers where regional transmission planning is working.[159]  The final rule points to the MISO Multi-Value Project transmission planning process as an effective example of regional transmission planning.[160]  From this, it could be concluded that the final rule suggests that regional transmission planning is working in MISO, including on a long-term basis.  It is logical to conclude similarly regarding CAISO’s[161] and New York’s regional transmission planning.[162]  Vertically integrated monopoly public utilities have expanded their transmission capacity by engaging in integrated resource planning that is reviewed and approved by their state regulators.[163]  NRECA, an organization representing both transmission providers and transmission-dependent entities, highlights that its members have observed regional transmission planning processes that range from successful to broken.[164]  According to NRECA, some RTO regions are working, and others are not.  NRECA similarly states that some non-RTO regions are working, and others are not.

This is hardly ironclad evidence sufficient to support a generic finding that the regional transmission planning processes are no longer just and reasonable.  The record here shows that regional and multistate regional planning is happening in significant and large swaths of the country subject to our rate jurisdiction, including on longer-term horizons, and that other regions have room for improvement.  These circumstances are entirely different than those facing the Commission when it issued Order No. 1000.  The factual justification for a single, national FPA section 206 finding is simply not present in the way it was for Order No. 1000.  No amount of hand waving or misdirection can change the lack of sufficient evidentiary support for this Commission to take the sweeping national action pursuant to FPA section 206 in this rule.  This significant deficiency leaves this entire exercise open to meaningful challenge.

The Replacement Rate Is Not Just and Reasonable

Not only does the final rule fail to meet its evidentiary burden, but the replacement rate that the final rule imposes is not just and reasonable and has no basis in law.  The final rule has removed any serious state role in agreeing to the final rule’s planning and cost allocation processes, and the final rule fails to protect consumers as FERC is required to do under the FPA.  Further, the cost causation principle cannot, and should not, extend as far as the today’s final rule suggests, and should not require that the ratepayers of a non-consenting state pay costs of other states’ public policies where there is mismatch between planning criteria and benefits. 

The Final Rule Reverses the States’ Roles in Transmission Planning and Cost Allocation Promised by the NOPR

The main reason I supported the NOPR was that it “formally put the states — for the first time — at the center of regional transmission planning and cost allocation decision-making for policy-driven projects in all regional transmission entities, if the states choose.”[165]  Specifically, I explained:

[F]or these [Long-Term Regional Transmission Facilities] the NOPR propose[d] to require the regional planning entities to consult with and seek the agreement of the relevant states to both the selection criteria for these projects and to the regional cost allocation arrangements.  State approval is especially important in a multi-state region, where different states have different policies.  The NOPR proposes to provide the maximum opportunity for creativity and flexibility to the states and regional entities in developing the process for designing and approving regional selection criteria and cost allocation arrangements.  States can agree to an ex ante formula for regional cost allocation of these types of projects — such as, for example, the “highway-byway” formula approved by the SPP Regional State Committee — or states can agree to a process for a project-by-project agreement on cost allocation among one or several states — such as, for example, the State Agreement Approach in PJM — or states may choose some combination of both.  States in a multi-state RTO or ISO can even agree to defer the decision on cost allocation to the governing board of the RTO/ISO.  The result is, while we are proposing to require regional planning entities to study and evaluate a broad, forward-looking array of information — including information addressing states’ individual energy policies and goals — any projects identified through this new process will not be built, or more importantly, paid for by consumers, until the states representing such consumers have agreed that such projects are indeed needed and wanted by those same consumers.[166]

I wrote about the advantages of elevating the role of the states:

[E]levating the role in planning and cost allocation of state regulators — who are, as a group, deeply concerned about the monthly bills paid by consumers, of which transmission is a rapidly growing component — will make it more likely, not less, that necessary transmission can get built while ensuring that rates resulting from these types of policy-driven projects will not be unjust and unreasonable, which they clearly have the potential to be.[167] 

The day the Commission issued the NOPR, some of my colleagues expressed similar sentiments.[168]

Unfortunately—perhaps emanating from the final rule’s erroneous legal conclusion that the Commission has exclusive jurisdiction over regional transmission planning and cost allocation[169]—the final rule completely eviscerates the states’ role contemplated in the NOPR in both the transmission planning and cost allocation processes.  Other than a few cosmetic gestures, the final role essentially treats the state regulators like other stakeholders in the RTO/ISO.  But states are not mere “stakeholders:”

State regulators have the duty to act in the public interest and states alone are sovereign authorities with inherent police powers to regulate utilities through their designated state officers.  The FPA itself explicitly recognizes state authority.  So it is perfectly fitting for state regulators to have the important roles proposed in this NOPR, without preempting the regional planning entities from seeking additional input through their existing stakeholder processes.[170]

The evisceration of the states’ role in transmission planning and cost allocation and the relegation of state regulators to mere “stakeholder” status is alone reason enough for me to dissent.

The Final Rule Undercuts the States’ Role in the Transmission Planning Process

A major example of the final rule’s undercutting of the states’ role in the transmission planning process is with respect to the selection criteria.  As a reminder, the selection criteria are a key component of the planning process because once a project is selected, money starts to flow from the ratepayers to transmission developers.  Recognizing the states’ important role in the planning process, the NOPR required that the states approve the selection criteria that transmission providers use in the planning process:

Given the important role states play and the wide variety of potential approaches to selection criteria, we propose, as part of this requirement, that public utility transmission providers must consult with and seek support from the relevant state entities, as defined below, within their transmission planning region’s footprint to develop the selection criteria.[171]

To implement this requirement, the NOPR proposed “to require that public utility transmission providers demonstrate on compliance that they developed their proposed selection criteria in consultation with the relevant state entities in their transmission planning region’s footprint.”[172]  And it was clear at that time exactly what that meant—agreement, nothing less.[173]  However, the final rule outright undermines these requirements—and the states’ role as a whole—by “clarifying” that state approval of the evaluation process and selection criteria is not actually required:

We clarify that we require transmission providers to seek support from Relevant State Entities, but do not require transmission providers to obtain their support, before proposing an evaluation process and selection criteria on compliance.[174]

Starkly demonstrating how milquetoast the requirement for transmission providers to “consult with and seek support from” the states has now become under the final rule, the final rule even fails to require that transmission providers indicate in their compliance filings whether the states agree with their selection criteria proposal.[175]  So, from the NOPR requiring state agreement, the final rule does not even require the states’ views to merit mere mention.  Adding insult to injury, the final rule specifies that “transmission providers may not include in their evaluation process or selection criteria any prohibition on the selection of a Long-Term Regional Transmission Facility based on the transmission providers’ anticipated response of a state public utility commission or consumer advocates to particular Long-Term Regional Transmission Facilities.”[176]  

The final rule acknowledges that “Long-Term Regional Transmission Planning is more likely to be successful where transmission providers, Relevant State Entities, and other stakeholders collaborate to develop an evaluation process and selection criteria.”[177]  But the final rule emphasizes that transmission providers are ultimately the only ones responsible for transmission planning and complying with the obligations of the final rule, and it notes that achieving consensus may simply not be possible in every instance.[178]  Neither explanation provides a sufficient rationale to justify undercutting the requirement for state approval when states alone have the inherent police power to regulate the utilities within their states.  One cannot help but see this as part of the larger pretextual shell game the final rule seeks to accomplish.  Sadly, this is one of many examples where the final rule provides for a little extra process involving the states to demonstrate ostensibly that the Commission is committed to the principle of cooperative federalism, but in substance, states are relegated back to mere stakeholders, whose input can simply be disregarded if inconvenient.[179]

Unfortunately, not only the states’ role with respect to the selection criteria has been gutted.  As I must continue emphasize,[180] by mandating categories of factors and minimum benefits, the final rule seeks to shape specific policies and outcomes, regardless of the consent of the states.[181]  The goal of this pretextual final rule is to plan preferential policy and corporate-driven projects regardless of states’ support.  One must also ask whether the extent to which this final rule requires prescriptive planning processes also limits the states’ role to participate meaningfully when most are resource-strapped.

States did not join RTOs[182] to pay for these preferential policy and corporate-driven projects.  Rather, as I wrote in my concurrence to the NOPR, “States joined to provide their retail consumers with the promised benefits of lower transmission costs and strengthened reliability through regional planning of core Reliability projects.”[183]  I speak from personal experience.  When I was a Commissioner at the Virginia State Corporation Commission, my colleagues and I considered applications to permit Virginia’s major utilities to join PJM.  The Virginia Commission’s rules required us to examine “among other things, an [RTO’s] reliability practices, pricing and access policies, and independent governance.”[184]  When we voted to approve the applications, PJM’s planning for public policy projects that would be cost allocated regionally was not even on our radar.  

The Final Rule Guts the States’ Role in Cost Allocation as Proposed in the NOPR

Given the pretextual nature of this rule, it should not be surprising that it eviscerates the states’ role in deciding cost allocation matters.  NARUC strongly supported the NOPR’s proposal to involve states in the cost allocation for Long-Term Regional Transmission Facilities and conversely disagreed with a requirement that transmission providers include a Long-Term Regional Transmission Cost Allocation Method in their OATTs without being obligated to seek agreement from the states.[185]  NARUC explained:

[S]ince the projects under consideration in the Long-Term Regional Transmission Planning process are largely driven by state public policies, state regulators should have a key role in evaluating the benefits and allocating the costs.  State regulators are attuned to the concerns of the local communities where the transmission will be sited and the retail ratepayers who must, in many instances, foot a large fraction of the cost.[186]

Of course, to effectuate the pretextual agenda, the final rule simply ignores NARUC’s entreaties and instead cuts the states out of any meaningful role in cost allocation.  

First, the final rule essentially terminates the State Agreement Process by making the ex ante cost allocation method the default approach.  While the NOPR proposed to require transmission providers to revise their OATTs to include either (1) an ex ante cost allocation method (i.e., a Long-Term Regional Transmission Cost Allocation Method) to allocate the costs of Long-Term Regional Transmission Facilities, (2) a State Agreement Process, or (3) a combination thereof,[187] the final rule substantially modifies the NOPR proposal to require the use of one or more ex ante cost allocation methods.[188]  Although the final rule permits transmission providers to include a State Agreement Process in their OATTs if the states agree, the final rule specifies that the State Agreement Process “cannot be the sole method filed for cost allocation for Long-Term Regional Transmission Facilities,”[189] and the final rule modifies the NOPR proposal to require an ex ante cost allocation method to apply as a backstop.[190]  The ex ante cost allocation method backstop would apply if a State Agreement Process fails to result in a cost allocation method agreed to by Relevant State Entities and others or if the Commission ultimately finds that the cost allocation method that results from a State Agreement Process is unjust, unreasonable, or unduly discriminatory or preferential.[191]

Second, under the final rule, state consent on cost allocation is not required.  The final rule explicitly declines to adopt the NOPR proposal to require transmission providers to seek the agreement of the states regarding the relevant cost allocation method to be applied to Long-Term Regional Transmission Facilities.[192]  Instead, the final rule merely requires transmission providers to establish a six-month Engagement Period “to provide a forum” for the states to negotiate an ex ante cost allocation method(s) and/or a State Agreement Process.[193]  Under the final rule, if the negotiations fail, transmission providers must still file an ex ante cost allocation method(s).[194]  Worse still, the final rule specifies that, even if the states do reach an agreement on an ex ante cost allocation method(s) and/or a State Agreement Process, the transmission providers may ignore it and file their own ex ante cost allocation method(s) instead.[195]  Similarly, the final rule declines to require that, if the transmission providers disagree with a proposed cost allocation method agreed on by the states, transmission providers must file both cost allocation methods:  the transmission providers’ preferred cost allocation method and the cost allocation method agreed to by the Relevant State Entities.  So to the states, the final rule says, “Heads I win, tails you lose.”

Further, under the final rule, at the end of the Engagement Period, the states’ role—however small—in shaping an ex ante cost allocation formula is effectively over.  NARUC argued that the Commission should provide some mechanism for future review of cost allocation methodologies for Long-Term Regional Transmission Facilities given that state public policies may evolve:  

As the name suggests, these transmission facilities are expected to be planned over a longer period of time than projects built for reliability or economic reasons.  States that do not currently have public policies requiring extensive transmission investments may forego an opportunity to participate in discussions regarding cost allocation, but their public policies may evolve over time.  For the reforms proposed in this NOPR to be successful, the positions of relevant state entities should not be frozen in time.[196]

But the final rule denies this request.[197]  Further, the final rule specifies that transmission providers may file subsequent changes to their cost allocation method(s) without establishing future Engagement Periods beyond the initial one.[198]

As noted above, the upshot of these changes, taken together, is that the states are simply cut out of any significant role in the cost allocation of the of Long-Term Regional Transmission Facilities.  The final rule completely eviscerates the State Agreement Process and renders it non-viable.  The final rule eliminates the core element of that approach—that states enter such cost allocation arrangements voluntarily.  Now—with an ex ante cost allocation method that must serve as a backstop in the event that the states’ negotiations fail, looming over the states’ heads like the sword of Damocles—the final rule gives states “an offer they can’t refuse,” telling the states that must they agree to a cost allocation or the transmission providers will impose one on them anyway.  In such a circumstance, fruitful negotiation between the states is virtually impossible, as states simply cannot say “no.”  At the risk of stating the obvious, this forced cost allocation on the states is, of course, contrary to comments of NARUC and many of the individual states.[199]

Just as concerning, as I discuss in Sections I and IV.B.2 of this dissent, the final rule will enable the ratepayers of non-consenting states to be assessed the cost of public policy projects of other states, which is anti-democratic and violates the basic principle of fairness.  As NARUC points out, NARUC and individual state commissions supported the State Agreement Process to address this concern:

NARUC is particularly supportive of the State Agreement Process, which is similar to the PJM State Agreement Approach that has been approved by FERC and that NARUC and state commissions advocated to be included in the final rule.  A state agreement approach allows states to further their public policy goals without burdening the ratepayers of states that have different priorities.[200]

The final rule’s gutting of the very State Agreement Process that NARUC supports as part of the final rule’s choice to ignore the consent of the states on cost allocation removes this key protection for the states and their ratepayers.

Further, given the final rule’s determinations undercutting the states’ role, I highly doubt that PJM’s State Agreement Approach or other existing mechanisms involving the states in other RTOs will remain viable with respect to the cost allocation of Long-Term Regional Transmission Facilities.[201]  In addition to PJM’s State Agreement Approach, NARUC notes that the country’s other multi-state RTOs have mechanisms in place for the states to participate in regional transmission cost allocation:

In many regions, state regulators are at the forefront of successful efforts to coordinate regional transmission, including what many understand to be the most challenging issue, cost allocation.  For instance, in SPP, the Regional State Committee has the primary authority for setting the basis of any regional cost allocation.  In both MISO and ISO-New England, state committees have the ability to propose alternative cost allocation methodologies under some circumstances.[202]

Specifically, SPP has a Regional State Committee (RSC) process by which the RSC has agreed to a “highway-byway” ex ante cost allocation and SPP will file it,[203] and MISO’s Tariff provides that MISO will file under FPA section 205 OMS’s alternative cost allocation to MISO’s proposal.[204]  Given that the final rule’s determination that transmission providers may ignore any agreement or alternative proposed by the states,[205] such mechanisms could be called into question—unless the RTOs voluntarily agree to preserve them in their OATTs.[206]  If these mechanisms are weakened, or even eliminated, the only alternatives left for the states to shape the RTOs’ cost allocation would be to file comments to the RTOs’ cost allocation filings or to file a section 206 complaint—no different than any RTO stakeholder.

The final rule acknowledges that “experience with Order No. 1000 has reinforced the critical role that states play in the development of new transmission infrastructure, particularly at the regional level, where transmission projects may physically span, and their costs may be allocated across, multiple states.”[207]  However, the final rule’s determinations on cost allocation undercut this critical role.  It appears obvious that the final rule does not in fact view the states as partners in a cooperative federal system, but rather as potential obstacles to its pretextual political, corporate, and ideological agendas.

The final rule sets forth two central arguments for its dramatic reduction of the states’ role.  First, the final rule suggests that, per Atlantic City,[208] the Commission cannot deprive transmission providers of their FPA section 205 filing rights to propose tariff changes to rates.[209]  And second, the final rule claims that if transmission providers were permitted to rely solely on a State Agreement Process to determine the cost allocation and that process were to fail, “there would be no cost allocation method for Long-Term Regional Transmission Facilities selected as the more efficient or cost-effective solutions to Long-Term Transmission Needs,” and “[a]s a result, such selected Long-Term Regional Transmission Facilities would be less likely to be developed, and the benefits that these facilities would provide would not be realized.”[210]  Both arguments are without merit.

The Final Rule Takes Far Too Broad a View of Atlantic City

Atlantic City is often discussed as a bar to FERC’s ability to take meaningful action on many issues, including transmission cost allocation.[211]  But Atlantic City does not stand for an outright prohibition on Commission action, especially under FPA section 206, under which this pretextual rule purports to act.  All Atlantic City stands for is that “transmission-owning utilities have ‘filing rights’ under section 205 that FERC may not revoke.”[212]  Atlantic City does not prevent FERC from granting additional filing rights to other entities, including state regulators, if it determines that existing practices, including RTO independence, are unjust and unreasonable and unduly discriminatory or preferential.[213] 

In a similar vein, Atlantic City does not require FERC to force non-consenting states to pay for other states’ policy projects, as today’s final rule implies.[214]  The final rule’s reliance on Atlantic City in this regard is simply a way for FERC to sidestep action that will truly ensure that needed transmission gets built with the cooperation, support, and assent of the states.  Instead, what we have in today’s final rule is a patent instance of regulatory capture with the singular goal to build out preferential policy and corporate-driven projects, steamrolling the states and consumers alike.  And to be clear, nothing meaningfully prevents the NOPR compromise that would have maintained or elevated the states’ role in transmission planning and cost allocation even further.  In fact, even accounting for Atlantic City, the NOPR compromise was a worthwhile solution to getting the transmission that is actually needed to serve organic load built. 

The Commission Fails Consumers by Unreasonably and Unfairly Socializing Policy- and Corporate-Driven Costs Across Captive Customers

The final rule’s claim that the Long-Term Regional Transmission Facilities selected are “the more efficient or cost-effective solutions to Long-Term Transmission Needs”[215] is disingenuous.  As I discuss above in Section I, in a sleight of hand move, the final rule lumps together in one bucket for planning and for cost allocation purposes projects that address policy-driven and corporate-driven needs with those that address reliability and economic needs.  The final rule’s goal is to socialize the costs associated with preferential policy and corporate-driven projects across the multi-state regions, even when the states have never consented for their consumers to pay for such projects.  But requiring the ratepayers of a non-consenting state to pay for the public policy projects of another state cannot reasonably be deemed “efficient” or “cost-effective.”

The Final Rule Requires Consumers in Non-Consenting States to Pay the Costs of Other States’ Public Policy Projects

The Costs of Public Policy-Driven Projects Must Not be Imposed on Non-Consenting Consumers Without State Regulatory Oversight

In my NOPR Concurrence, I noted that “no individual state’s consumers can be forced to bear the costs of another state’s policy-driven project or element of a project against its consent.”[216]  I have adamantly maintained this position in subsequent Statements:

The costs related to a public policy project . . . should be borne by the sponsoring state and not shifted to consumers in other states without the consent of responsible officials in those states, who can then be held accountable by the voters of that state for their decisions (as can officials in the sponsoring state).  That is how democracy is supposed to work.[217]

I have explained that if the people and businesses of the sponsoring state do not like the impacts of their state’s public policies, “their recourse is to the ballot box,”[218] but that in contrast, “[c]onsumers in other states do not have such recourse, which is why these costs must be confined to [the sponsoring state].”[219] 

I have written before that “imposing the costs of a project driven by one state’s public policies onto another state that has not consented to such cost allocation would, in my view, presumably result in unjust and unreasonable rates.”[220]  Such imposition would be contrary to basic fairness, a core principle of American democracy: 

For if democracy means anything at all, it means that the people have an inherent right to choose the legislators to whom the people grant the power to decide the major questions of public policy that impact how the people live their daily lives. . . .  That is the basic constitutional framework of the United States and it is the same for any liberal democracy worth the name.[221]

The final rule subverts this principle.[222]

 

      1.  

Certain States Are Not “Cost Causers” for Cost Allocation Purposes

Today’s final rule provides very little in the way of support for its cost allocation requirements, despite the extensive changes to planning requirements.[223]  This final rule simply assumes that it is on sound footing as to cost causation.  But that is not the case.  While some precedent cited by today’s final rule sheds some indirect light on the cost allocation issues implicated here,[224] at its core, today’s final rule involves a new application of the cost causation principle to justify the final rule’s pretextual agenda.  It intends to force consumers in one state to pay for the costs of public policies enacted by politicians in another state and corporate purchasing preferences.  But those costs and the resulting rates cannot be considered just and reasonable in any universe.

We are at the point where we must argue that not all consumers in certain states are “cost causers” simply because they have joined a multi-state RTO or fall within a transmission planning region.  These consumers are not the “but for” cause of many of the Long-Term Transmission Needs required by the consideration of the specified categories of factors in today’s policy agenda-driven rule.  Nor are such consumers the intended beneficiaries of public policies in states enacted by politicians for whom they never voted.  Indeed, absent rational limits on the “free rider” concept that the cost causation principle is meant to address, anyone can be deemed a beneficiary of any transmission project anywhere. 

That policy-caused costs cannot be attributed to consumers who did not cause the policy is consistent with case law.  As articulated mostly clearly by the D.C. Circuit, the cost causation principle means that “all approved rates [must] reflect to some degree the costs actually caused by the customer who must pay them.”[225]  This has been oft repeated by many courts over the years, including most notably the U.S. Court of Appeals for the Seventh Circuit (Seventh Circuit) in Illinois Commerce Commission v. FERC.[226]  The Seventh Circuit expanded on this further to state that, “[t]o the extent that a utility benefits from the costs of new facilities, it may be said to have ‘caused’ a part of those costs to be incurred, as without the expectation of its contributions the facilities might not have been built, or might have been delayed.”[227] 

Tied to the cost causation principle is the concept of “free ridership.”  As explained by the Commission in Order No. 1000-A, a free rider is an “entity is not required to pay for a benefit it receives”[228] and is the form of “subsidization” against which the cost causation principle is supposed to protect.[229] 

As explained in Order No. 1000-A, the Commission treats each transmission customer not as using a single transmission path but rather as usual the entire transmission system and views such service as service over the entire grid.[230]  The Commission explained:

Given the nature of transmission operations, it is possible that an entity that uses part of the transmission grid will obtain benefits from transmission facility enlargements and improvements in another part of that grid regardless of whether they have a contract for service on that part of the grid and regardless of whether they pay for those benefits.  This is the essence of the “free rider” problem the Commission is seeking to address through its cost allocation reforms.  Any individual beneficiary of a new transmission facility has an incentive to defer investment in the anticipation that other beneficiaries in the region will value the project enough to fund its development.  This can lead to situations in which no developer moves forward, adversely affecting development of transmission facilities and, as a result, rates for jurisdictional services.[231]

Therefore, the Commission explained that the cost allocation provisions of Order No. 1000 (the failures of which allegedly justify the changes contemplated by today’s final rule), which seek to allocate costs to beneficiaries in a region roughly commensurate with benefits they receive, were consistent with the statement in ICC that “[a]ll approved rates [must] reflect to some degree the costs actually caused by the customer who must pay them.”[232]  Indeed, all of the precedent relied upon in today’s final rule signals that free ridership is a concern solely based on the assumptions underlying the transmission planning.  And herein lies the deception—the more you plan and account for, the bigger and more regionalized you can argue the cost allocation framework should be.  Which makes sense when the goal of today’s final rule is to enact a sweeping policy agenda and thus socialize the costs across consumers in a multi-state region.

The main support for the cost causation principle is ICC,[233] for the exact quote noted above.  However, often omitted from the discussion of ICC is the context and outcome of the case.  In that case, the Seventh Circuit remanded the Commission’s approval of cost allocation concerning “Project Mountaineer”[234] (yes, the same one that prompted PATH) for lack of substantial evidence regarding the FERC-approved cost allocation.  In addition to the quote above, the Seventh Circuit also expressed the following:  “FERC is not authorized to approve a pricing scheme that requires a group of utilities to pay for facilities from which its members derive no benefits, or benefits that are trivial in relation to the costs sought to be shifted to its members.”[235]  And it merits repeating that “[t]o the extent that a utility benefits from the costs of new facilities, it may be said to have ‘caused’ a part of those costs to be incurred, as without the expectation of its contributions the facilities might not have been built, or might have been delayed.”[236]  So, given the extent to which the Long-Term Transmission Needs contemplated by today’s final rule factor in state public policies and special interests’ goals, you would expect the only beneficiaries for cost allocation purposes to be states with those public policies or other special interest drivers of the transmission. 

Unfortunately, you would be wrong.  Due to the final rule requiring planning for any and every transmission need and mandating minimum reliability and economic benefits as part of the planning process, projects developed primarily for preferential policy and corporate purposes will necessarily have the broadest array of so-called beneficiaries possible, all identified prior to selection.[237]  These so-called beneficiaries will then be forced to pay for these projects, simply because they may receive some trivial benefits due to their participation in a regional transmission system.  These so-called beneficiaries will be treated as “cost causers” even though their contributions do not ensure the projects get built nor ensure that the projects are not delayed.  Today’s final rule, of course, even emphasizes that, as to why today’s final rule does not require the consideration of public policy benefits, it “does not allow allocation of costs based on benefits to entities that do not receive benefits or receive only trivial benefits in relationship to costs of those transmission facilities.”[238]  But this is because today’s final rule already determined the minimum reliability and economic benefits that all projects contemplated by the final rule must have.  Adding in public policy benefits would shift the resulting cost allocation to show the actual beneficiaries—the states with preferred policies and corporate and special interests.  So, through a mismatch in planning criteria and benefits, today’s final rule ensures socializing the costs of preferential policy and corporate-driven projects onto states and consumers that will ultimately receive trivial benefits, in violation of ICC.  If you find all this confusing, the final rule is intended to be.  That’s why it’s a shell game.

At its core, ICC is simply a baseline regarding the cost causation principle’s application.  That is, the Commission cannot require cost allocation to a particular group of utilities, i.e., consumers, where there is no evidence of benefits.  Its findings should not be distorted, as today’s final rule suggests through Orwellian newspeak, to support a mismatch of planning criteria to benefits to strongarm a cost allocation regime to get preferential policy and corporate-driven projects built.

Also referenced by today’s final rule for cost causation is South Carolina.[239]  In the context of cost causation, the D.C. Circuit concluded that “the Commission’s adoption of a beneficiary-based cost allocation method is a logical extension of the cost causation principle.”[240]  The court added that it had “endorsed the approach of ‘assign[ing] the costs of system-wide benefits to all customers on an integrated transmission grid.’”[241] 

The final rule does not simply require a beneficiary-based cost allocation, like Order No. 1000.  Instead, as I must continue to emphasize, it requires mandating reliability and economic benefits during the planning process to shoehorn the broadest group of beneficiaries possible for projects that do not remotely relate to reliability and economic needs.[242]  This is not a “light touch” that “does not dictate how costs are to be allocated.”[243]  Today’s final rule may attempt to sequester the beneficiaries of these reliability and congestion benefits from the cost allocation “benefits” by not clearly linking the two,[244] but in what reality will a transmission provider seeking to comply with today’s final rule identify different beneficiaries from those identified in the planning process?  The result of this shell game is to ensure preferential policy and corporate-driven projects are selected with the widest group of beneficiaries possible, so as to socialize the costs across the widest group of consumers.[245] 

Today’s final rule ultimately presents the wrong solution to the perceived problem of “balkanized” transmission planning.[246]  Unfortunately, today’s final rule devises the shell game to ensure that the biggest planning bucket means the biggest pool of potential beneficiaries.  And to carry out the shell game, the final rule walks back cost allocation principle (6) because, without this change, today’s final rule’s preferred cost allocation framework does not work.[247] 

NARUC and many individual states oppose the Commission’s imposition of mandatory minimum benefits and would prefer a bottom-up rather than a top-down approach:  “The proposed list of benefits for consideration is a better way to accomplish the objectives of the NOPR than specification of benefits that must always be used in Long-Term Regional Transmission Planning.”[248]  Today’s final rule blithely brushed these concerns aside.

To effectuate purported compliance with the cost causation principle, today’s final rule ignores the principle of the optimal solution in transmission planning.  For each identified reliability problem, there is an optimal solution that solves the reliability problem at the least cost to consumers.   For an economic project, consumers should receive the maximum reduction in congestion costs relative to the cost of the project, or put in another way, for a given reduction of congestion costs, consumers should pay the least costs for the project.  The final rule, by contrast, claims that a project that is driven by one state’s public policies will still provide some reliability and congestion benefits to other states, so consumers in those states must be treated as beneficiaries.[249]  But even assuming that consumers in those other states hypothetically receive some marginal reliability or congestion benefits, they are being overcharged for those benefits because the project includes the costs of another state’s public policies or costs of projects to meet corporate goals, and the only benefits required to be considered by today’s final rule are reliability and economic benefits.  Consumers in the non-policy causing states are not receiving or paying for the optimal solution to an identified reliability problem or maximum congestion relief compared to the costs they are being forced to pay.  As a consequence, the transmission rates—let’s ignore the planning practices for a moment—they will be forced to pay are clearly unjust and unreasonable under the FPA. 

The Final Rule Violates the Commission’s Consumer Protection Duty Under the FPA

To add to the number of already unjust and unreasonable aspects in today’s final rule, today’s final rule is patently unfair to consumers.  That much is apparent from its decision, through transmission planning and cost allocation processes:  (1) to shift interconnection costs from generation developers to consumers through transmission planning, and (2) to shift the costs of, inter alia, a transmission project accommodating a corporate commitment from corporate consumers to other consumers.  Today’s final rule, equally harmful to consumers, walk backs the NOPR proposal to remove the CWIP Incentive, one of the major reasons I supported the NOPR in the first place.  The final rule essentially uses the justification of efficiency and cost-effectiveness to create catastrophic outcomes for consumers.  Such an anti-consumer outcome is simply unjust and unreasonable, and in this case, even unduly discriminatory and preferential.

The Final Rule Unlawfully Shifts Interconnection Costs from Developers to Consumers

In prior statements, I have frequently discussed the basic principle that generation developers should pay the costs to interconnect their generators to the grid:

[G]eneration developers in RTOs should pay the full “but for” costs of their interconnection, including network upgrades.  Consumers (i.e., load) should not pay one nickel.  They are not the ones seeking to profit from the interconnection.  New generation in RTOs is supposed to be driven by the market, not by integrated resource planning, as in non-RTOs.  This is the compelling principle underlying participant funding of interconnection in RTOs.[250]

By requiring the coordination of regional transmission planning and generator interconnection processes and by requiring the incorporation of Factor Category Six: generator interconnection requests and withdrawals in the development of Long-Term Scenarios, the final rule causes consumers to subsidize generation developers and thus subverts this basic principle.

Coordination of Regional Transmission Planning and Generator Interconnection Processes Will Result in Unlawful Cost Shifts to Consumers

The final rule requires transmission providers in each transmission planning region to revise their existing Order No. 1000 regional transmission planning processes to evaluate for selection regional transmission facilities that address certain identified interconnection-related transmission needs associated with certain interconnection-related network upgrades originally identified through the generator interconnection process.[251]  As a result of this requirement, transmission providers may select in regional transmission plans for purposes of cost allocation transmission facilities designed to address certain interconnection needs and will allocate the costs of such facilities to the load in that region.  This practice will force consumers to subsidize the interconnection costs of generator developers and in so doing turn them into the banks for the ventures, viable or otherwise, of generation developers — a classic example of the socialization of costs to enable private profit.  Of course, this will result in rates that are blatantly unjust, unreasonable, unduly discriminatory and preferential.

The final rule’s attempted justifications for this effort to shift interconnection costs to consumers are vacuous and fail to disguise the real agenda, which is to subsidize developers of preferred resources.  For example, the final rule asserts that reforms are necessary because “it may be more efficient or cost-effective to address [interconnection-related transmission needs] through the regional transmission planning and cost allocation process.”[252]  The final rule professes that its requirements “will result in selection of more efficient or cost-effective regional transmission solutions that will provide benefits to the transmission system, cost allocation for such regional transmission facilities that is at least roughly commensurate with estimated benefits, and elimination of a barrier to entry for new generation resources (which will enhance competition in wholesale electricity markets and facilitate access to lower-cost generation).”[253]  But more efficient or cost-effective for whom?  Certainly not for consumers who will be conscripted to subsidize tens or hundreds of millions of dollars of interconnection costs so that generator developers may more cheaply interconnect and make higher profits (and likely receive government subsidies).  The final rule’s speculation that extracting such subsidies from consumers will “facilitate access to lower-cost generation” is purely pretextual.   

The final rule notes that “the Commission has found, and courts have affirmed, that interconnection-related network upgrades identified in the generator interconnection process can provide widespread transmission benefits that extend beyond the interconnection customer.”[254]  Further, it asserts that the regional transmission facilities designed to address the interconnection needs “may have the potential to provide more widespread benefits to transmission customers.”[255]  Today’s final rule does not even come close to justifying the enormous cost shifts this will place on consumers.

The final rule summarily brushes aside the concern that its reform will shift interconnection costs from interconnection customers (i.e., generation developers) to load.[256]  It explains that “[t]ransmission providers will still have to evaluate and select any regional transmission facilities that address the interconnection-related transmission needs as the more efficient or cost-effective regional transmission solution as part of the regional transmission planning process in order for any regional cost allocation method to apply.”[257]  The final rule also explains that “if such a facility is selected, the Commission-approved ex ante regional cost allocation method for that facility would allocate its costs at least roughly commensurate with its estimated benefits.”[258]  But the regional cost allocation methods allocate cost only to load, not to generation.  So, how could allocating interconnection costs to load enable them to be “roughly commensurate to benefits” when generator developers, the primary beneficiaries of the transmission facilities and the “but for” cause of their development be allocated nothing?  Here, as elsewhere, the final rule deviates from the FPA’s consumer protection purpose:  under the final rule, rather than generation existing to serve load, load is being conscripted to serve (the profits) of generation.

Finally, the final rule’s conclusion that it will not incentivize gaming by interconnection customers to include interconnection-related network upgrades in the regional transmission planning process is detached from reality.[259]  The final rule notes that interconnection requests require significant financial commitments from the interconnection customer (e.g., application fees, study deposits, and site control requirements) and that interconnection customers employing such a strategy would face several risks.[260]  As with so much FERC does, today’s final rule woefully underestimates at its peril the profit-seeking, and at times, gambling behavior of generator developers.  In issuing this final rule, the Commission appears to forget that a main driver in issuing Order No. 2023 was to reduce speculative interconnection requests and interconnection request withdrawals spurred by this behavior.[261]  Despite the significant financial commitments and risks that the final rule describes, I can foresee generators submitting speculative or spurious interconnection requests in the efforts to be subsidized by load if the estimated interconnection costs are high enough.  In any event, I think it obvious that, ceteris paribus, the final rule will encourage more disruptive withdrawals—particularly for requests that necessitate high interconnection costs—as the final rule provides generator developers dissatisfied with high interconnection costs a chance at another bite at the apple.  And of course, apples taste sweeter when they’re paid for by someone else.

Factor Category Six Will Result in Unlawful Cost Shifts to Consumers

For similar reasons, I oppose the final rule’s requirement that transmission providers in each transmission planning region incorporate in the development of Long-Term Scenarios, Factor Category Six:  interconnection requests and withdrawals.[262]  Such a requirement would ultimately result in consumers paying for the transmission that generators need to interconnect to the grid.  This again is a way to cost shift interconnection costs from generation developers to consumers. 

Factor Category Seven Forces Some Consumers to Subsidize Others

The Commission’s requirement that transmission providers incorporate Factor Category Seven, utility and corporate commitments and federal, federally-recognized Tribal, state, and local goals that affect Long-Term Transmission Needs, in the development of Long-Term Scenarios[263] is unjust and unreasonable because it will unfairly saddle consumers with unnecessary transmission costs that they did not cause.  In addition, comments on Factor Category Seven identify several additional regulatory and practical obstacles that the final rule attempts to resolve by allowing transmission providers to dial the impact of these commitments and goals up or down.[264]  Further, this provision is yet another count in the final rule’s pattern of diminishing the states’ role in regional transmission planning by elevating mere corporate preferences to have equal if not greater stature as the policy choices of states and federally-recognized Tribes.

It is worth starting the examination of Factor Category Seven simply by pulling the curtain back and highlighting the coalitions of comments that the final rule cites supporting it and opposed to it.[265]  The strongest support for this provision comes from where we would all expect:  the corporate interests with something to gain by shifting the costs that result from their preferential power purchase commitments to others along with the other special interests whose policy preferences have no place in developing a rate that is just and reasonable.[266]  I am similarly unsurprised that the skeptics and opponents of this provision are led by retail rate authorities, load-serving entities from coast to coast, and large multi-state RTOs.  They understand that adopting Factor Category Seven is unfair, unworkable, and a mistake. 

Factor Category Seven is as unlawful as it is unfair because it grossly violates cost causation principles of ratemaking.[267]  Whether a corporate commitment or a state/Tribal policy goal is directly attributed to increased transmission costs, the entities with the self-imposed aspirations are the direct beneficiaries.  Cost causation principles of ratemaking—not to mention reviewing courts—will dictate that those entities, and not any other transmission customer, are the beneficiaries of the resulting transmission built to accommodate the corporate commitments.  As the direct beneficiaries, they will be responsible for the increased transmission costs driven by those commitments, goals, and preferences.  Even worse, if one of these cost causers changes its commitment or goal, all of the transmission provider’s customers could still be left paying for the increased costs that are no longer attributable to any beneficiary.  This is not how a just or reasonable rate works.

Even if the unfair and unlawful Factor Category Seven is allowed to take effect, it will fail on its own terms for practical reasons.  The final rule acknowledges that the corporate commitment or a state/Tribal policy goal are “more likely to change over the transmission planning horizon than factors in other required factor categories.”[268]  As a balm for this uncertainty, the final rule grants the transmission providers the discretion to apply the salve of a discount on the likelihood that any of these aspirations will come to pass.  Nothing in the final rule will prevent transmission providers from discounting these commitments one hundred percent.  This discount is simply an invitation for transmission providers to ignore Factor Category Seven.

Even worse, when a transmission provider expends its limited resources to read the tea leaves of corporate commitments and include them in the Long-Term Scenarios, that inclusion will result in a violation of the FPA.  Applying the costs of one corporation’s commitments to all of the transmission provider’s customers amounts to undue discrimination against similarly situated customers without corporate commitments while bestowing an undue preference for those similarly situated customers with corporate commitments.  Further, most utility customers are at a resource and access disadvantage to the deep-pocketed special interests (including the corporate commitments driven by their wealthy and sophisticated investor class) that enjoy influence and power.  Rather than sticking the consumers with any part of the bill for the gold plating necessary for a different customer’s corporate preferences, this Commission should not depart from its cost allocation precedent.  Under that precedent, the beneficiaries are required to pay for the upgrades they are driving.  This Commission should not now saddle less powerful people and small businesses with the costs of the choices made by influential corporations and their managers and investors.[269]

Let me be clear about how egregious and unfair this idea is with a hypothetical scenario.  Suppose that a Fortune 500 company pressured by its investors commits to a corporate goal that it will only purchase electric power from certain preferred generation sources within a decade.  It similarly commits to discriminate against power sourced from non-preferred generation resources.  The transmission provider then informs the corporate customer that transmission upgrades will be necessary in order for those favored generation resources to actually deliver power to the corporate customer’s facilities and to avoid receiving power from the non-preferred resources.  Next, the transmission provider includes those upgrades in Factor Category Seven.  Later, the transmission provider builds the necessary upgrades according to its regional transmission plan and incurs significant cost in doing so.  Instead of attributing those costs to the corporate customer, the transmission provider socializes the upgrade costs to all of its customers.  Rather than holding the actual cost causer accountable for the increase, the final rule instead dictates that the costs directly resulting from the customer’s corporate commitment benefit all ratepayers because there are necessarily reliability and economic benefits that result from all transmission development.  Then these increased costs are socialized across all of the transmission provider’s customers.  This realistic outcome is, to put it mildly, grossly unfair to consumers and a violation of the FPA.

Now suppose that a neighboring corporate customer (that receives an identical class of electric service as the customer in the prior hypothetical) announces in response its own corporate goal that it will never consider any factors other than reliability and cost in purchasing electric power because it wants to keep its costs as low as possible no matter what.  How is a transmission provider supposed to accommodate that second corporate goal?  Do the two commitments simply cancel each other out?  Will the transmission provider carve out the second corporate customer?  Where would that leave the customers who are silent with respect to these competing corporate goals?  The final rule fails to answer these questions.

The Final Rule Walks Back the NOPR Proposal to Remove the CWIP Incentive

Today’s final rule also walks back the widely supported proposal to remove the CWIP transmission incentive.  As I have discussed above, it is apparent that the pretextual goal of this final rule is to get transmission built to serve political and corporate goals, no matter the cost and no matter who actually benefits from it.

As I noted on numerous occasions, a core principle of utility law and regulation for decades is that consumers can be forced to pay costs only for assets that are “used and useful” to them.  In Order No. 679, the Commission determined that it may be necessary to depart from this long-standing ratemaking principle to “address the substantial challenges and risks in constructing new transmission.”[270]  And in my prior statements, I questioned, among other concerns, whether the Commission’s determination of whether “substantial challenges and risks” exist when granting the various transmission incentives has becoming nothing more than a check-the-box exercise.[271]  In particular, I noted:

The Commission’s incentive policies—particularly the CWIP Incentive, which allows recovery of costs before a project has been put into service—run the risk of making consumers “the bank” for the transmission developer; but, unlike a real bank, which gets to charge interest for the money it loans, under our existing incentives policies the consumer not only effectively “loans” the money through the formula rates mechanism, but also pays the utility a profit, known as Return on Equity, or “ROE,” for the privilege of serving as the utility’s de facto lender.[272]

The proposal to remove the CWIP Incentive was a major reason why I supported the NOPR, despite its flaws, and a massive step in the right direction to remedy the harm to consumers that these incentives have caused over the years.[273]  However, instead of adopting the proposal to remove the CWIP Incentive, today’s final rule chose to side with developers and special interest groups, rather than with consumers.  Today’s final rule rationalizes the decision to walk back the removal of the CWIP Incentive by finding that any action on the CWIP Incentive is more appropriately considered in a separate proceeding where incentives can be comprehensively evaluated for all regional transmission facilities.[274]  I regard that as nothing more than an excuse for a continuing failure to act.

Many commenters share my concerns that the CWIP Incentive inappropriately shifts risks to ratepayers and runs afoul of the core principle of utility law and regulation that consumers should pay costs only for assets that are “used and useful” to them.[275]  Others argue that removing the CWIP Incentive may mitigate the risk of overbuilding that may result from the other changes cemented in today’s final rule.[276]  Today’s final rule, however, is astoundingly silent on the consumer impact of retaining the CWIP Incentive.

Unfortunately, this is simply a continuation of the Commission punting on any meaningful reevaluation of transmission incentives.  In my three years on the Commission, there has been no action to reevaluate the check-the-box award of transmission incentives, and it is far past time for me to begin dissenting from this lack of action on the Commission’s part to change this shameful status quo.[277]  By walking back the removal of the CWIP Incentive, today’s final rule reveals, one again, its failure to protect consumers as required by the FPA.

Conclusion

Had the states been given the authority to protect their consumers, as promised by the NOPR, I would have supported this rule just as I voted for the NOPR, as an imperfect but acceptable compromise.[278]  If transmission projects that are planned to implement public policies—the product of political decisions made by politicians—or to implement corporate “green energy” power purchasing preferences—the product of corporate management and investors—are going to be included in long-term planning mandated by FERC, then the states must have the authority to consent to (i) the planning criteria (which determines which projects go into regional plans and receive cost recovery from consumers), and (ii) the formula for regional cost allocation of such projects.  

This role for the states is not only essential but fair:  fair to state policymakers and regulators and fair to the tens of millions of consumers they represent.  The final rule, however, denies states that essential role and that denial renders this order unfair to the states and unfair to tens of millions of consumers.

As has been said before, denial is not just a river in Egypt.  The short-sightedness of the final rule and the special interests who lobbied this Commission to deny states this key role is a denial of the reality of how transmission actually gets built in the union of states that is the United States of America.  As a former state regulator who voted to approve scores of transmission projects, both regional and local, I will testify from experience that to get transmission built—especially the big, controversial regional lines of 500 kV and above—the states should not be dismissed as annoying obstacles that must be pushed out of the way by an omnipotent, omniscient FERC.  Rather, state regulators must be respected as potential partners and, most importantly, advocates of such controversial lines, who will be invested in them and work to get them sited and built within their borders.  That will never happen if states are denied the role that I advocated in the NOPR, that of full partners in deciding how, when and whether their consumers are burdened with costs for politically and corporate-driven policy projects.  

This final rule could have corrected the single biggest flaw in Order No. 1000:  the exclusion of the states from decision-making roles in FERC-mandated regional transmission planning for public policy projects.  Instead, the final rule doubles down on that error with a blizzard of new planning mandates to serve political, corporate, and ideological agendas, while leaving the states with no real power to protect their consumers from the trillions of dollars of costs that this order brazenly wants to impose on them.  The final rule is nothing but a pretext for enacting a sweeping policy agenda that Congress never passed.  As such, it blatantly violates the major questions doctrine.  In producing rates that will be unjust, unreasonable, and unduly discriminatory and preferential, it violates the actual text of the FPA.  And in that violation, it fails to fulfill our most important duty under the FPA, which is to protect consumers.

 

For these many reasons, I respectfully dissent.

 

[1] E.g., Towns of Alexandria, Minn. v. FPC, 555 F.2d 1020, 1028 (D.C. Cir. 1977) (explaining that the FPA’s “‘primary aim is the protection of consumers from excessive rates and charges’”) (quoting Mun. Light Bds. v. FPC, 450 F.2d 1341, 1348 (D.C. Cir. 1971)); see also Elec. Dist. No. 1 v. FERC, 774 F.2d 490, 492 (D.C. Cir. 1985) (recognizing that the benefits of rate predictability, which are the “whole purpose” of the filed rate doctrine, ought to be considered in light of the FPA’s “primary purpose of protecting the utility’s customers”).

[2] 16 U.S.C. 824e.  Under the FPA, the Commission is a regulator of wholesale public utility rates, not a national integrated resource planner (known in the lingo as an “IRP”) of generation and/or transmission.  See, e.g., Entergy Nuclear Vt. Yankee, LLC v. Shumlin, 733 F.3d 393, 417 (2d Cir. 2013) (quoting S. Cal. Edison Co. San Diego Gas & Elec. Co., 71 FERC ¶ 61,269, at 62,080 (1995) (“[S]tates have broad powers under state law to direct the planning and resource decisions of utilities under their jurisdiction. States may, for example, order utilities to build renewable generators themselves, or . . . order utilities to purchase renewable generation.”).  Further, FPA section 215, pertaining to electric reliability, explicitly leaves the construction of generation and transmission assets to state regulatory authority.  16 U.S.C. 824o(i)(2).  Section 215 makes clear congressional intent to leave integrated resource planning to the states.  Indeed, the overall statutory framework of the FPA—consistent with America’s federal constitutional structure—makes it clear that states are the primary regulators of which utility assets get planned and built, both generation and transmission, not FERC.

[3] See, e.g., W. Va. v. EPA, 597 U.S. 697 (2022) (West Virginia v. EPA); Dept. of Commerce v. N.Y., 139 S. Ct. 2551 (2019).

[4] In truly Kafkaesque fashion, the final rule is a doorstopper weighing in at just below 1300 pages, likely one of the longest, most complicated, and confusing orders the Commission has ever issued.  Regulated entities—it applies to all public utility transmission providers in the United States, RTO and non-RTO—will need weeks just to read through it, much less decipher it, and then months of figuring out how to comply.  Its very complexity raises the prospect of multiple rounds of compliance filings, no doubt punctuated by multiple deficiency letters, in order to push the transmission provider towards the outcomes the Commission wants to achieve.  The final rule’s very complexity renders it, if not arbitrary and capricious on its face, likely to be arbitrary and capricious in its enforcement.

[5] See, e.g., Heather Richards, Zach Bright, Christian Robles, 3 energy issues to watch this spring at DOE, Interior and FERC, Energywire, Mar. 18, 2024 (“FERC has promised a closely watched rule this spring on transmission that could be key to President Joe Biden’s ambitious aim to decarbonize the electricity grid by 2035. . . .  ‘The sooner we get a final rule, the better. . . ,’ said Caitlin Marquis [of] Advanced Energy United, a pro-clean-energy group. . . .  [T]he Biden administration is in a race . . . until roughly midyear to finalize rules before they are subject to the Congressional Review Act (CRA) . . . .  The Biden administration has said [today’s final rule] will facilitate a build-out of interregional lines and grid interconnections needed to . . .  allow more wind and solar power to come online. . . .”) (emphases added) https://www.eenews.net/articles/3-energy-issues-to-watch-this-spring-at-doe-interior-and-ferc/; see also Peter Behr, EPA power plant rule targets coal.  Does that spell trouble for the grid? Climatewire, May 3, 2024 (“But climate activists will not give up the ‘zero by 2035’ goal without a fight.  President Biden made that steep commitment at a critical point in his 2020 candidacy to win the support of primary rival Sen. Bernie Sanders (I-Vt.) and his climate action activists. . . .  [T]he hard road to a zero-carbon grid in 2035 is real precisely because the Biden administration has pursued it. . . .  [Study authors] highlighted estimates that the rate of high-voltage transmission line construction must double to deliver the necessary new wind and solar energy. . . .  The [Biden] administration . . . is putting a strategy for big new lines in place.  FERC, with the support of Biden appointees, is preparing new policy to support big wires projects. . . .  ‘You can’t get around the fact that you’re going to need tens of thousands of miles of new transmission lines if you want to build the hundreds of gigawatts of wind and solar and batteries that many of us predict are needed to achieve decarbonization goals,’ said [former Obama energy secretary Ernest] Moniz.”) (emphases added), https://www.eenews.net/articles/epa-power-plant-rule-targets-coal-does-that-spell-trouble-for-the-grid-2/; see also Zach Bright, FERC sets date for landmark transmission rule, Energywire, Apr. 19, 2024 (“FERC said it plans to hold a special May 13 meeting to consider its . . . transmission planning and cost-allocation proposal that’s been a focus of [lobbying] for expanding the grid to . . . move more renewable energy. . . The Biden administration’s goal of [net zero] by 2035 hinges on expanding the transmission system by two-thirds, the Energy Department said last year.”) (emphases added), https://www.eenews.net/articles/ferc-sets-date-for-landmark-transmission-rule/; It’s raining rules:  Why the Biden administration is rushing to produce regulations, The Economist, May 4, 2024, at 19 (“More regulations, big and small, are expected soon.  The Federal Energy Regulatory Commission is planning to rewrite the rules governing interstate electricity transmission, which is critical to President Joe Biden’s decarbonisation plans. . . .  Why the sudden spate?  A previously obscure law, the [CRA], helps explain the rush.  It allows Congress, for a limited period, to pass resolutions of disapproval against finalised administrative regulations with which it disagrees.  If both chambers of Congress pass such a resolution, and the president signs it, the rule is cancelled, short-circuiting the usual drawn-out process of litigation or a subsequent administration beginning a whole new rule-making effort.  So once a regulation is properly created the clock starts ticking:  the cancellation procedure is allowed for up to 60 days that the Senate is in session—including the last 60 days of an administration that loses a presidential election.”) (emphasis added), https://www.economist.com/united-states/2024/05/02/why-the-biden-administration-is-rushing-to-produce-regulations; see infra nn.8, 10, 13, 15, 16, 67.

[6] The transmission component of utility service has typically been provided by the incumbent monopoly utility at the load-serving local level, and local transmission planning and/or construction is generally subject to state-regulated IRP or permitting processes, especially in non-RTO regions.  The final rule imposes numerous additional requirements for local transmission planning, including even micromanaging how local “stakeholder” meetings are supposed to be conducted, which may conflict with state IRP proceedings and represent yet another FERC encroachment into areas of traditional state authority.  See Bldg. for the Future Through Elec. Reg’l Transmission Planning & Cost Allocation & Generator Interconnection, Order No. 1920, 187 FERC ¶ 61,068, at Section IX.B.3.a (2024) (Final Rule).  It is highly doubtful that the micromanagement of stakeholder meetings in local planning would pass judicial review under CAISO v. FERC, in which FERC’s attempted micromanagement of an ISO’s governing board appointments was rejected as not sufficiently grounded in FERC’s rate-setting authority under the FPA.  See Cal. Indep. Sys. Operator Corp. v. FERC, 372 F.3d 395, 400 (D.C. Cir 2004) (CAISO v. FERC).

[7] The Princeton Net Zero study is often cited, but it is only one of many estimates of the trillions of dollars in additional costs to be imposed on consumers.  Using the Princeton study, the cost estimates of the transmission buildout necessary to achieve “net zero” range across different scenarios, with one scenario calling for transmission capacity to quintuple (5x) between 2020 and 2050, which is predicted to cost $3.56 trillionSee Princeton University Net Zero America Final Report Summary, Slide 29, https://netzeroamerica.princeton.edu/img/Princeton%20NZA%20FINAL%20REPORT%20SUMMARY%20(29Oct2021).pdf.  I would emphasize that the sticker price of a utility asset is only a fraction of the ultimate cost to consumers, because the “going in” price will increase by a multiple of many times the original cost over the life of the asset, because the cost of capital, both a profit to the utility (known as Return on Equity, or ROE) and the cost of debt, will be paid by consumers.  So, if Princeton gives an estimate of $3.56 trillion for new utility assets needed to reach the “net zero” goal, the actual cost to consumers over the life of the assets will be many times more than that estimate.  See also Diana DiGangi, US won’t reach net zero emissions without transmission buildout:  DNV, Utility Dive, Sept. 25, 2023 (“$12 trillion will be spent on clean energy in North America by 2050 . . . to meet . . . net zero emissions targets . . . .  Some of the biggest barriers to net zero in the U.S. include the lack of transmission buildout . . . .) (emphases added), https://www.utilitydive.com/news/net-zero-transition-clean-energy-north-america-transmission-buildout/694621/.

[8] See, e.g., Peter Behr, DOE unveils critical grid corridors for Biden climate goals, Energywire, May 8, 2024 (“‘To meet our climate goals we have to more than double our transmission capacity,’ said top White House clean energy adviser John Podesta, who has led a Cabinet-level push to get long-delayed transmission projects under construction.”) (emphasis added), https://www.eenews.net/articles/doe-unveils-critical-grid-corridors-for-biden-climate-goals/; Peter Behr, More, More, More:  Biden’s clean grid hinges on power lines, Energywire, May 23, 2022 (stating that “the Biden administration is seeking an unprecedented expansion of high-voltage electric lines to open new paths to wind and solar energy.  ‘We obviously need more, more, more transmission to run on 100 percent clean energy. . . ,’ Energy Secretary Jennifer Granholm said in February.”) (emphasis added), https://subscriber.politicopro.com/article/eenews/2022/05/23/more-more-more-bidens-clean-grid-hinges-on-power-lines-00030117; see also supra n.5 and infra nn.10, 13, 15, 16, 67. 

[9] 467 U.S. 837 (1984) (Chevron).

[10] See Catherine Morehouse, FERC to tackle “historic” transmission planning rule in May, PoliticoPRO, Apr. 18, 2024 (“FERC has been under enormous pressure from lawmakers, clean energy developers, environmentalists and others to finalize the rule that Chair Willie Phillips has promised will be ‘historic’ and the ‘greatest development regarding electric transmission rules in the country in over a generation.’”) (emphases added), https://subscriber.politicopro.com/article/2024/04/ferc-to-tackle-massive-transmission-planning-rule-next-month-00153191; see also, e.g., Sen. Charles E. Schumer July 24, 2023 Comments at 1-2 (urging the Commission to ensure that “any final rule must . . . prescribe a set of benefits” to be used in transmission planning and that “it will be necessary that either” [the transmission provider, or FERC shall impose cost allocation] “when any state withholds support on a cost allocation method” [which risks] “states that benefit from a transmission line” [acting as] “free riders [to] avoid any costs.”) (emphases added); Sen. Martin Heinrich, et al. (consisting of 20 additional Senators) Jan. 19, 2024 Comments at 2 (urging the Commission that “the final rule must require consideration of a . . . specific set of transmission benefits for . . . cost allocation processes”) (emphases added); Sen. Sheldon Whitehouse Nov. 7, 2023 Comments at 2 (stating that “FERC should include [a list of required benefits] in its final rule”).  As explained extensively herein, mandating benefits is a device for imposing costs on consumers in states that never agreed to the selection criteria or cost allocation.  The deeply granular nature of the instructions to the Commission in these letters is more evidence that this final rule is a pretext to use an administrative agency to enact legislation that Congress never passed.  See also supra nn.5, 8 and infra nn.13, 15, 16, 67.

[11] Luigi Zingales, Preventing Economists’ Capture, University of Chicago Booth School of Business Review, July 1, 2014 (“In simple words, regulatory capture exists when a regulatory agency, created to act in the public interest, ends up advancing interests of the industry it is charged with regulating.”), https://www.chicagobooth.edu/review/preventing-economists-capture.

[12] The example of the Potomac-Appalachian Transmission Highline (PATH) fiasco is a strong warning about the folly of spending billions of consumers’ dollars to build transmission based on predictions of a generation mix in 20 years.  Potomac-Appalachian Transmission Highline, LLC, 185 FERC ¶ 61,198 (2023) (Christie, Comm’r, concurring at P 3) (PATH Concurrence) (“[C]onsumers have paid roughly $250 million for a project that was never built nor found needed by a single state regulator.”) (emphasis in original), https://www.ferc.gov/news-events/news/e-4-commissioner-christies-concurrence-letter-order-approving-path-settlement-er12; see also PJM Initial Comments at 62 (“In short, the volatility of input parameters cancelled the need for a $1.8 billion transmission line identified in 2007, that was confirmed to be needed five years out in 2012, but by 2012 was no longer needed for at least another 15 years, if at all.”).  Rather than wind or solar—which the final rule implicitly presumes will be the predominant generating resource in 20 years—it is just as foreseeable that the predominant share of generation in the U.S. could be nuclear, an essential dispatchable resource, as small modular reactor technology matures and economies of scale produce lower costs, or it could be green hydrogen.  It could even be fusion or some new technology currently either nascent or unknown.  No one knows today.  Building trillions of dollars of transmission on a prediction that intermittent wind and solar will be the predominant generating resource in 20 years is just a costly guess.

[13] See, e.g., Clean Energy Buyers Jan. 22, 2024 Comments (“Many of our businesses cannot grow without more clean generation resources . . . .  States may miss out on economic growth opportunities without . . . access to the types of generation resources needed to attract growing and innovative industries.”) (emphases added).  Among the signers of these comments were Amazon, Apple, eBay, Google, Green Impact Technologies, Meta, Microsoft, Nike, Rivian, Salesforce, Target, Walmart and several other multinational corporations.  The FPA gives FERC no authority whatsoever to use the “green energy” purchasing preferences of privately owned, for-profit multinational corporations as the basis to impose a mandatory transmission planning and cost allocation rule that will cost consumers trillions of dollars.  The FPA does not recognize such corporate preferences; indeed, the FPA forbids preferences.  See also supra nn.5, 8, 10 and infra nn.15, 16, 67.

[14] The Wizard of Oz (Metro-Goldwyn-Mayer 1939).

[15] See, e.g., Catherine Morehouse, DOE launches effort to cut federal permitting for new power lines in half, PoliticoPRO, Apr. 25, 2024 (“The [U.S. Dept. of Energy] program is the latest move by the Biden administration to speed up the . . . process for new transmission lines deemed critical to carrying dispersed wind and solar resources . . . .  It also comes on the heels of an announcement from the EPA to tighten emissions standards for fossil-fueled power plants — a move that will necessitate bringing more low-carbon resources onto the power grid to meet growing demand as [fossil fuel] resources are forced offline.  ‘DOE’s work complements what our partners across the administration are doing . . . to deliver cleaner power . . . ,’  Energy Secretary Jennifer Granholm told reporters . . . .”) (emphases added), https://subscriber.politicopro.com/article/2024/04/doe-launches-effort-to-cut-federal-permitting-for-new-power-lines-in-half-00154189; see also Catherine Morehouse, Energy regulator’s exit may flummox Biden’s green plans, Politico, Feb. 9, 2024 (“[FERC] is poised to lose its biggest climate advocate and potentially shut down one of the White House’s best avenues to push its green policies. . . .  That buildout is needed to accommodate . . . wind and solar projects that are critical to meeting the Biden administration’s climate and clean energy goals.”) (emphases added), https://subscriber.politicopro.com/article/2024/02/energy-regulators-exit-may-flummox-bidens-green-plans-00140774; Molly Christian, US transmission “in desperate need of an upgrade,” Vice President Harris says, Megawatt Daily, Jan. 20, 2023 (“Achieving lofty US climate goals will requirethousands of miles of new high-voltage transmission lines all across our country,’ US Vice President Kamala Harris said. . . .  ‘To create our clean energy future, we must construct thousands of miles of new high-voltage transmission lines all across our country,’ [Harris said].”) (emphases added), https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/electric-power/012023-us-transmission-in-desperate-need-of-an-upgrade-vice-president-harris-says; Alex Guillén, Ben Lefebvre, Annie Snider, Kelsey Tamborrino, Catherine Morehouse, James Bikales, Biden administration eyes spring to finalize key climate regulations, PoliticoPro, Dec. 6, 2023 (“The Biden administration is planning to finalize several major energy and environmental regulations in the first half of 2024 . . . .   That timeframe would help cement many of President Joe Biden’s policy priorities in the event he does not win reelection. . . .  One of the top [FERC] priorities . . . has been to finalize a rule on power line planning and cost allocation . . . . that is considered critical to unlocking new wind and solar resources.”) (emphases added), https://subscriber.politicopro.com/article/2023/12/biden-administration-plots-busy-spring-finalizing-key-climate-regulations-00130496.  See also supra nn.5, 8, 10, 13 and infra nn.16, 67.

[16] See Brad Plumer, Energy Dept. Aims to Speed Up Permits for Power Lines, The New York Times, Apr. 25, 2024 (“[Biden] Administration officials are increasingly worried that their plans to fight climate change could falter unless the nation can quickly add vast amounts of grid capacity to handle more wind and solar power . . . .  But experts say a rapid, large-scale expansion may ultimately depend on Congress.”) (emphases added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html.  See also supra nn.5, 8, 10, 13, 15 and infra n.67.

[17] Bldg. for the Future Through Elec. Reg’l Transmission Planning & Cost Allocation & Generator Interconnection, Notice of Proposed Rulemaking, 87 FR 26504 (May 4, 2022), 179 FERC ¶ 61,028, at P 303 (2022) (NOPR).

[18] See, e.g., Final Rule, 187 FERC ¶ 61,068 at P 265 (“[W]hat matters is that this final rule aims to regulate and, in fact, does regulate only practices that affect the transmission of electric energy in interstate commerce, which are squarely within the Commission’s jurisdiction under the FPA.”).

[19] See infra Section III.CThe final rule insists that it most assuredly does not implicate a major question of public policy, Final Rule, 187 FERC ¶ 61,068 at PP 275-279, much like Captain Renault in Casablanca is “shocked, shocked to find gambling going on in here” as he pockets his winnings.  Casablanca (Warner Bros. Pictures 1942); but see Brad Plumer, Energy Dept. Aims to Speed Up Permits for Power Lines, Apr. 25, 2024 (quoting Rob Gramlich, the president of the consulting group Grid Strategies, “‘I’ve called [the final] rule the biggest energy policy in the country.’”) (emphasis added), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html.  See Catherine Morehouse, FERC to tackle “historic” transmission planning rule in May, PoliticoPRO, Apr. 18, 2024 (quoting Chairman Phillips describing the final rule as “historic” and the “greatest development regarding electric transmission rules in the country in over a generation. . . .”) (emphases added).

[20] See, e.g., Final Rule, 187 FERC ¶ 61,068 at PP 1474 (“[T]ransmission providers may not establish reliability, economic, or public policy transmission facility types as part of Long-Term Regional Transmission Planning and, therefore, may not establish Long-Term Regional Transmission Cost Allocation Methods based on reliability, economic, or public policy transmission facility types.”).

[21] Id.; see also id. PP 41, 250-251.  In terms of labeling, at least Order No. 1000 described public policy projects honestly, as those that address “transmission needs driven by Public Policy Requirements.”  See, e.g., Transmission Plan. & Cost Allocation by Transmission Owning & Operating Pub. Utils., Order No. 1000, 136 FERC ¶ 61,051, at PP 2, 6 (2011), order on reh’g, Order No. 1000-A, 139 FERC ¶ 61,132, order on reh’g & clarification, Order No. 1000-B, 141 FERC ¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 762 F.3d 41 (D.C. Cir. 2014) (South Carolina); see also id. PP 11, 47.

[23] Final Rule, 187 FERC ¶ 61,068 at Section III.

[24] Id. P 409.  Among the mandatory categories of factors that the final rule dictates must be used to drive long-term planning throughout the entire country are, inter alia:  (i) state and local laws affecting the resource mix, (ii) state and local laws on decarbonization, (iii) generator interconnection requests and withdrawals (another way to subsidize and prefer wind and solar developers which dominate the queues), and (iv) corporate, state and local government commitments to purchase “green” energy.  Let me emphasize:  these planning factors are mandatory for transmission providers to use, exposing the final rule’s pretextual agenda for what it really is.

[25] Id. PP 3, 269, 719-720.

[26] See, e.g., id. P 720.

[27] Id. PP 1505-1511.

[28] Id. P 965.

[29] Id. P 1291. 

[30] See, e.g., id. P 1305 n.2786 (“The cost causation principle requires costs to be allocated to those who cause the costs to be incurred and reap the resulting benefits.”)  (emphasis added).  A true statement on its face, but utterly disingenuous here.  By mandating its preferred factors to be used in long-term planning, by mandating certain benefits to be used in evaluating projects, and by denying transparency as to what other benefits are used to evaluate projects and how benefits are being calculated, which drives cost allocation, the final rule effectively will hide the specific costs of policy and corporate-driven projects and essential information as to how costs are being calculated and allocated across a multi-state region.  See also supra n.10.

[31] These key elements of the shell game respond almost precisely to the lobbying demands of various interest groups.  See, e.g., Environmental Groups Dec. 8, 2023 Comments (“Transmission providers must perform long-term (at least 20-year), forward-looking assessments. . . .  They must . . . [include] planning for state clean energy laws and policies, [and] scenarios with high renewable penetration . . . .  Scenarios must evaluate all benefits that transmission projects would deliver and use these assessed benefits as a basis for project selection. . . .  The Commission also should create a default cost allocation policy that meets this same standard . . . .”) (emphases added).  Among others, the signers of this letter include:  Advanced Energy United, American Clean Power Association, Clean Air Task Force, Earthjustice, Environmental Defense Fund, Evergreen Action, League of Conservation Voters, National Wildlife Federation, Natural Resources Defense Council (NRDC), Sierra Club, Union of Concerned Scientists, and WE ACT for Environmental Justice.  See also supra nn.8, 10.

[32] Final Rule, 187 FERC ¶ 61,068 at P 267 (“[N]othing in this final rule requires states to subsidize other states’ public policies and, indeed, this final rule requires . . . that transmission customers within a transmission planning region need only pay costs that are ‘roughly commensurate’ with the benefits that transmission providers estimate they will receive from a transmission facility.”) (emphasis added).

[33] NOPR, 179 FERC ¶ 61,028 (Christie, Comm’r, concurring at PP 11-12, 14) (NOPR Concurrence); see also id. P 5.

[34] Id. P 11 (emphasis in original and added).

[35] Id. P 12 (emphasis added).

[36] Id. P 14 (emphasis in original and added).

[37] From the Transcript of Apr. 21, 2022 Commission Open Meeting (April 2022 Open Meeting Tr.):   

“CHAIRMAN GLICK: And I also want to finally thank my colleagues.  I think this [NOPR] is a really good product.  It is a product of a lot of discussion, a lot of compromise—which is what the Commission is all about—and I think all of us can say we did not get everything in there, in the document, that we would like, but I think we all got enough in there and I think we achieved a significant and really remarkable level of consensus.  And I think that is very notable today.”  April 2022 Open Meeting Tr. 44:17-24 (emphases added).

“COMMISSIONER CLEMENTS: As the Chairman [stated] that reaching agreement on this proposal was not easy.  I can say with confidence that none of us voting for it would have written it this way if we were writing on our ownBut I am proud that it is a bipartisan effort, and I am thankful to my colleagues for proactively engaging and for thinking creatively to find alignment.”  Id. at 55:17-23 (emphasis added).

“COMMISSIONER CHRISTIE:  But I think on balance the positive aspects of this [NOPR], particularly for state regulators at the heart of planning and cost allocation for these types of projects, changing [CWIP] to AFUDC[,] I think those are positive, big steps forward for me on balance and it makes it worth voting for this [NOPR].”  Id. at 67:15-20 (emphasis added).

“COMMISSIONER PHILLIPS:  I would first like to thank my colleagues for working collaboratively with me on this. . . .  I don’t think I have ever been a part of a process more collaborative than this process that we had in this NOPR.”  Id. at 67:24-25, 68:6-8.

To those who say that many elements of this final rule were also in the NOPR for which I voted, such as, for example, the mandatory categories of factors, I would respond:  If I agree to get a root canal with anesthetic, but learn upon arrival at the dentist’s office that I can still get the root canal but with no anesthetic, that is not the original deal.

[38] See infra Section II.

[39] Final Rule, 187 FERC ¶ 61,068 at P 996.

[40] Id. PP 3, 269, 719-720, 903.

[41] Id. PP 1291-1292, 1294, 1354, 1356 n.2895, 1359, 1367, 1429.

[42] Id.  To be clear, even if the states agreed on an alternative ex ante cost allocation method, or if they agreed on a cost allocation method under the State Agreement Process, the transmission provider could choose to file it but also could ignore itSee infra n.195.

[43] See Final Rule, 187 FERC ¶ 61,068 at PP 1291-1292, 1294, 1354, 1356 n.2895, 1359, 1367, 1429.

[44] The Godfather (Paramount 1972).

[45] Final Rule, 187 FERC ¶ 61,068 at P 1255 (“NARUC requests that the Commission provide a mechanism for future review of cost allocation methods for Long-Term Regional Facilities.” (citing NARUC Initial Comments at 49-50)).

[46] Id. P 1368; see also id. P 1291.

[47] See, e.g., id. PP 268, 959, 994, 996-997, 1456.

[48] Id. P 1363 (citation omitted).  A different attitude towards state regulators was apparent in the NOPR.  See April 2022 Open Meeting Tr. 46:10-16 (“CHAIRMAN GLICK:  [This] NOPR proposes to give the states a much more significant role in addressing cost allocation.  I think it helps to have Commissioner Christie and Commissioner Phillips, two of our five Commissioners are former state regulators, and I think that really helps to have their background and their interest.”).

[49] See Robert Walton, U.S. electricity prices outpace annual inflation, Utility Dive, Mar. 13, 2024 (“U.S. electricity prices rose 3.6% over the last 12 months, outstripping the broader inflation rate of 3.2%, the Bureau of Labor Statistics reported Tuesday.  And experts say there is little chance for near-term consumer relief. . . .  And federal policies aimed at electrifying end uses and reducing emissions could lead to even higher prices, Travis Fisher, director of energy and environmental policy studies at the Cato Institute, told a House subcommittee Wednesday.”) (emphasis added), https://www.utilitydive.com/news/us-electricity-prices-rise-customer-eia-outlook/710113/.

[50] See, e.g., Zach Bright, Electricity prices rise faster than inflation, EnergyWire, Apr. 12, 2024 (“The Bureau of Labor Statistics found that electricity prices rose 5 percent over the past year.  That’s higher than the overall consumer price index (3.5 percent) and any other single commodity, like food . . . and gasoline . . . .”) (emphases added), https://www.eenews.net/articles/electricity-prices-rise-faster-than-inflation/; Electricity Inflation 30% Higher Than CPI Over Last 12 Months” Electricity Transmission Competition Coalition, Apr. 10, 2024 (“Electricity inflation remains the highest consumer goods cost among the items in the Consumer Price Index according to the latest release of data by the Bureau of Labor Statistics. . . .  The price of electricity has soared because of the accelerating cost of transmission . . . .”) (emphasis added), https://electricitytransmissioncompetitioncoalition.org/electricity-inflation-30-higher-than-cpi-over-last-12-months/.

[51] State of the Market Report 2023, PJM Market Monitor, Vol. II, Section 1, at 18, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2023.shtml; State of the Market Report 2014, PJM Market Monitor, Vol. II, Section 1, at 16, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2014/2014-som-pjm-volume2-sec1.pdf; State of the Market Report 2013, PJM Market Monitor, Vol. II, Section 1, at 12, Table 1-9, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2013/2013-som-pjm-volume2-sec1.pdf; see also State of the Market Report 2019, PJM Market Monitor, Vol. II, Section 1, at 18, Table 1-10, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2019/2019-som-pjm-sec1.pdf.

[52] State of the Market Report 2020, PJM Market Monitor, Vol. I, at 17, Table 8, https://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2020/2020-som-pjm-vol1.pdf.

[53] See Jim O’Reilly, Led by AEP and Duke, transmission growth poised to rebound from dip in 2022, S&P Global Market Intelligence, Nov. 15, 2023 (showing bar graph providing that aggregate transmission rate base grew from $61.4 billion in 2012 to $163.1 billion in 2022), https://www.spglobal.com/marketintelligence/en/news-insights/research/led-by-aep-and-duke-transmission-growth-poised-to-rebound-from-dip-in-2022.  Under this Commission’s rate recovery protocols, the transmission owner gets to collect the annual costs of transmission depreciation from rate base, plus a profit, known as Return on Equity, or “ROE,” often inflated by the many incentives the Commission typically approves, as well as operations and maintenance costs.  As any utility regulator knows, “what goes into rate base comes out in customers’ bills.”  So a rapidly rising rate base means rapidly growing consumers bills. 

[54] Amanda Durish Cook & Tom Kleckner, Overheard at 10th Annual GCPA MISO-SPP Forum, RTO Insider, Mar. 12, 2024, https://www.rtoinsider.com/73311-overheard-10th-annual-gcpa-miso-spp-forum/.

[55] See, e.g., Final Rule, 187 FERC ¶ 61,068 at P 89.

[56] See supra n.7.

[57] Illinois Senator Everett Dirksen is said to have once quipped, “In Washington, a billion here, a billion there, and pretty soon you’re talking about real money.”  The final rule updates his quip to a “trillion here, a trillion there . . . .”

[58] George Orwell, 1984 (first published by Secker & Warburg 1949).

[59] See, e.g., Office of Ohio Consumers’ Counsel v. Am. Elec. Power Serv. Corp., 181 FERC ¶ 61,214 (2022) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-addressing-rto-adders-related-e-2-ohio; MISO, 181 FERC ¶ 61,094 (2022) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-urging-action-re-rto-participation-adder-docket; Mary O’Driscoll, FERC approves incentives for AEP, Allegheny grid projects, Greenwire, July 21, 2006 (“The approvals came as the commission finalized rules intended to promote transmission-grid additions that outline specific rate and other incentives that FERC will consider for future construction projects — the ‘FERC candy’ that critics contend gives the utilities incentives but not much in the way of corresponding requirements.”) (emphasis added), https://subscriber.politicopro.com/article/eenews/2006/07/21/ferc-approves-incentives-for-aep-allegheny-grid-projects-234508.

[60] Final Rule, 187 FERC ¶ 61,068 at P 1547.

[61] Baltimore Gas & Elec. Co., 187 FERC ¶ 61,030 (2024) (Christie, Comm’r, dissenting at P 7), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-incentives-exelon-er24-1313; PJM Interconnection, L.L.C., 185 FERC ¶ 61,200 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/e-7-commissioner-christies-concurrence-exelons-application-abandoned-plant; The Potomac Edison Co., 185 FERC ¶ 61,083 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-potomac-edisons-abandoned-plant; Montana-Dakota Utils. Co., 185 FERC ¶ 61,015 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-montana-dakota-utilities-co-regarding; Midcontinent Indep. Sys. Operator, Inc., 184 FERC ¶ 61,136 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc-0; GridLiance W. LLC, 184 FERC ¶ 61,129 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-gridliance-west-regarding-transmission; Midcontinent Indep. Sys. Operator, Inc., 184 FERC ¶ 61,034 (2023) (Christie, Comm’r, dissenting at P 8), https://www.ferc.gov/news-events/news/commissioner-christies-dissent-award-transmission-incentives-nipsco-er23-1904; Otter Tail Power Co., 183 FERC ¶ 61,121 (2023) (Christie, Comm’r, concurring at P 8), https://www.ferc.gov/news-events/news/e-18-commissioner-christies-concurrence-otter-tail-power-company-regarding; LS Power Grid Cal., LLC, 182 FERC ¶ 61,201 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-ls-power-grid-regarding-transmission-incentives; Nev. Power Co., 182 FERC ¶ 61,186 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nv-energy-regarding-transmission-incentives; The Dayton Power and Light Co., 182 FERC ¶ 61,147 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-dayton-power-and-light-company-regarding; Midcontinent Indep. Sys. Operator, Inc., 182 FERC ¶ 61,039 (2023) (Christie, Comm’r, concurring at P 3), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-midcontinent-independent-system-operator-inc; NextEra Energy Transmission Sw., LLC, 180 FERC ¶ 61,032 (2022) (Christie, Comm’r, concurring at P 3) (July 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-nextera-energy-transmission-southwest-llc; NextEra Energy Transmission Sw., LLC, 178 FERC ¶ 61,082 (2022) (Christie, Comm’r, concurring at P 3) (February 2022 Concurrence), https://www.ferc.gov/news-events/news/commissioner-mark-c-christie-concurrence-nextera-energy-transmission-southwest-llc.

[62] NOPR Concurrence at P 15.

[63] By doing nothing about the consumer-paid “FERC candy” incentives that this Commission regularly hands out to developers, and even removing the provisions dialing back the CWIP incentive—and with its overall aim to pile trillions of dollars of additional costs for big corporate and politically-driven transmission on consumers, which will largely flow to the increased profits of wind, solar and transmission developers—the final rule could be the inspiration for one of the great country and western songs “Lord Have Mercy on the Working Man.”  Warner Bros. Nashville 1992 (“Why’s the rich man busy dancing while the poor man pays the band?  Oh they’re billing me for killing me, Lord have mercy on the working man!”).

[64] Final Rule, 187 FERC ¶ 61,068 at PP 472, 1106-1107, 1126, 1145.

[65] Id. PP 125, 1106-1107, 1126, 1145.  Under “participant funding” mechanisms the generation developer pays the costs of the network upgrades costs it causes and consumers do not pay, which is only fair.  The Commission’s Order No. 2023 did not violate this principle.  See generally Improvements to Generator Interconnection Procs. & Agreements, Order No. 2023, 88 FR 61014 (Sept. 6, 2023), 184 FERC ¶ 61,054, order on reh’g, 185 FERC ¶ 61,063 (2023), order on reh’g, Order No. 2023-A, 89 FR 27006 (Apr. 16, 2024), 186 FERC ¶ 61,199 (2024).  This final rule clearly intends to undermine this principle by moving interconnection costs into regional transmission planning and cost allocation, so consumers get stuck with the costs of interconnection, even though it is developers who profit from interconnection. 

[66] Final Rule, 187 FERC ¶ 61,068 at P 472.

[67] See Miranda Willson, Heather Richards, Brian Dabbs, Biden regulatory plan set to shake up energy sector, Energywire, Dec. 7, 2023 (“The White House released a regulatory plan Wednesday that could shape President Joe Biden’s energy legacy . . . .  [T]wo of the Federal Energy Regulatory Commission’s most high-profile proposed transmission rules are listed on the [White House] agenda . . . .  One of those FERC rules would change how large electric power lines are planned and paid for . . . .”) (emphases added), https://www.eenews.net/articles/biden-regulatory-plan-set-to-shake-up-energy-sector/; see also supra nn.5, 8, 10, 13, 15, 16.

[68] In the very recent past, this Commission stood up for its independence despite intense pressure from a presidential administration.  See, e.g., Steven Mufson, Trump-appointed regulators reject plan to rescue coal and nuclear plants, The Washington Post, Jan. 8, 2018 (explaining that “[t]he independent five-member commission [that rejected the president’s proposal] includes four people appointed by President Trump”), https://www.washingtonpost.com/news/energy-environment/wp/2018/01/08/trump-appointed-regulators-reject-plan-to-rescue-coal-and-nuclear-plants/.

[69] The process leading to the adoption of Order No. 1000, the final rule’s direct predecessor but one not nearly as sweeping in its application, was described in paragraphs 22 through 24 of that order.  Order No. 1000, 136 FERC ¶ 61,051 at PP 22-24.

[70] Final Rule, 187 FERC ¶ 61,068 at PP 1291-1292.

[71] Id. PP 3, 269, 719-720.

[72] See NOPR, 179 FERC ¶ 61,028 at PP 9, 245.

[73] See id. P 302.

[74] See Order No. 1000, 136 FERC ¶ 61,051 at P 685.

[75] Final Rule, 187 FERC ¶ 61,068 at P 1469 (“[U]nlike under Order No. 1000, transmission providers cannot adopt different Long-Term Regional Transmission Cost [A]llocation Methods for different types of Long-Term Regional Transmission Facilities, such as those needed for reliability, congestion relief, or to achieve Public Policy Requirements.”) (emphasis added); see also id. P 1474.

[76] See, e.g., id. PP 1291-1292.  A more detailed discussion on how the final rule effectively guts the State Agreement Process is in infra Section IV.B.1.b.

[77] See Final Rule, 187 FERC ¶ 61,068 at P 1323 (citations omitted).

[78] Id. P 1547.

[79] See NOPR, 179 FERC ¶ 61,028 at P 333; NOPR Concurrence at P 15.

[80] See NOPR, 179 FERC ¶ 61,028 at PP 400-413.

[81] Final Rule, 187 FERC ¶ 61,068 at P 1625.

[82] See id. PP 86, 253.

[83] See supra Section I.

[84] 762 F.3d 41.

[85] E.g., Final Rule, 187 FERC ¶ 61,068 at PP 86, 253, 256 & n.604, 257 & n.605, 277.

[86] Id. P 16 (citing Order No. 1000, 136 FERC ¶ 61,051 at P 3).

[87] South Carolina, 762 F.3d at 54 (citing Chevron, 467 U.S. 837).

[88] Id. (quoting Chevron, 467 U.S. at 842).

[89] See, e.g., id. at 84.

[90] Id. at 54 (quoting Chevron, 467 U.S. at 843).

[91] See, e.g., id. at 58-59 (citing Chevron, 467 U.S. at 843), 84.

[92] Id. at 76 (citing Nat’l Cable & Telecomms. Ass’n v. Brand X Internet Servs., 545 U.S. 967, 982 (2005)).

[93] Note, however, that the U.S. Supreme Court is revisiting the 40-year-old doctrine and has indicated that it may narrow or overturn it in the pending cases, Loper Bright Enterprises v. Raimondo, No. 22-451 (argued Jan. 17, 2024) and Relentless v. Dep’t of Commerce, No. 22-1219 (argued Jan. 17, 2024).

[94] See South Carolina, 762 F.3d at 56-59 (internal citations omitted).

[95] Id. at 57-58 (emphasis added; internal citations omitted).

[96] Id. at 89-90 (citation omitted).

[97] Id. at 91 (emphasis in original; internal citations omitted).

[98] Id. at 84-86.

[99] Id. at 81.

[100] In so doing, the final rule violates section 201 as well.  See infra Section III.B.

[101] See South Carolina, 762 F.3d at 89-90.

[102] This factor category is another way to subsidize and prefer wind and solar developers, which dominate the interconnection queues.

[103] Final Rule, 187 FERC ¶ 61,068 at PP 38-39 (emphasis added).

[104] Id. PP 42, 633 (emphasis added).

[105] Id. PP 40 and 302 (emphasis added). 

[106] See South Carolina, 762 F.3d at 58 (internal citation omitted).

[107] Final Rule, 187 FERC ¶ 61,068 at P 965.

[108] 16 U.S.C. 824(b)(1) (emphases added).

[109] See, e.g., Entergy Nuclear Vt. Yankee, LLC v. Shumlin, 733 F.3d at 417 (quoting S. Cal. Edison Co. San Diego Gas & Elec. Co., 71 FERC at 62,080).

[110] 762 F.3d at 62-64.

[111] Id. at 63 (emphasis added) (footnote omitted)

[112] Id. (internal citations omitted).

[113] Id. at 64.

[114] See Final Rule, 187 FERC ¶ 61,068 at PP 954-955, 1026-1028.

[115] Id. P 965.

[116] NOPR Concurrence at P 2; see also id. n.4 (quoting Order No. 1000, 136 FERC ¶ 61,051 at P 154 (“[T]he regional transmission planning process is not the vehicle by which integrated resource planning is conducted; that may be a separate obligation imposed on many public utility transmission providers and under the purview of the states.”) (emphases added in NOPR Concurrence)).

[117] Id. P 12 (emphases in original).

[118] See, e.g., CAISO v. FERC, 372 F.3d at 400 (holding that FERC cannot prescribe the membership of the CAISO board, as FERC has authority over only “rates, charges, classifications, and closely related matters”); see also Ari Peskoe, Replacing the Utility Transmission Syndicate’s Control, Energy Law Journal, Vol. 44.3 547, 578 (2023) (Peskoe Article) (“FERC’s authority over utility ‘practices’ is best understood as referring to ‘actions habitually being taken by a utility in connection with a rate found to be unjust and unreasonable.’”) (footnote omitted), https://www.eba-net.org/wp-content/uploads/2023/11/8-Peskoe547-618.pdf.

[119] FERC regulates RTOs and RTO markets to ensure just and reasonable rates to consumers, but FERC has no authority to order a load-serving public utility to build a specific generation facility, only states can.  See 16 U.S.C. 824(b)(1); see also Hughes v. Talen Energy Mktg., 578 U.S. 150, 154 (2016) (“The States’ reserved authority includes control over in-state ‘facilities used for the generation of electric energy.’” (quoting 16 U.S.C. 824(b)(1))); see also 16 U.S.C.824o(i)(2) (“[Section 215 of the FPA] does not authorize the [Electric Reliability Organization, i.e., NERC] or the Commission to order the construction of additional generation or transmission capacity or to set and enforce compliance with standards for adequacy or safety of electric facilities or service.”).  Congress recently gave FERC a narrowly limited form of “backstop” siting authority for certain designated transmission lines, but that authority is not implicated in this final rule. 

[120] PATH Concurrence at P 4 (“PATH graphically illustrates the inherent dangers in approving for regional cost allocation long-distance projects based on a prediction (i.e., a guess) of what the generation mix will be in 20 years or more.  PATH was originally part of the huge “Project Mountaineer” scheme—announced with great fanfare right here at the Commission itself – to build three high-voltage lines across hundreds of miles from West Virginia to East Coast load centers.  The vast majority of the power to be delivered along these lines was to be coal-generated.  After running into a firestorm of opposition in both the states in the path (no pun intended), as well as the end-user load states, Project Mountaineer was abandoned except for the PATH project, which represented a segment of one of the proposed Project Mountaineer lines.  That segment was never built either.  Yet, consumers have been paying for it ever since.  The lesson here is clear:  For policy-driven long-distance, regional transmission projects affecting consumers in multiple states, it is absolutely essential that state regulators have the authority to approve – or disapprove – the construction of these lines and how they are selected for regional cost allocation and what that cost allocation formula is, if their consumers are going to be hit with the costs.”) (emphasis in original).

[121] Final Rule, 187 FERC ¶ 61,068 at P 263; see also, e.g., id. P 271 (“[T]he requirements in this final rule respect and do not unlawfully infringe on state authority.  Rather . . . the Commission is acting in an area squarely within its jurisdiction—transmission planning and cost allocation—by requiring transmission providers to engage in Long-Term Regional Transmission Planning to remedy deficiencies in the current transmission planning and cost allocation processes.”).

[122] E.g., id. PP 129, 130, 254, 259-263, 266, 271, 275.

[123] You can decide for yourself whether the “green curtain” represents “green energy” or something else that’s green.

[124] See supra Sections I, III.B.

[125] See supra nn.5, 8, 10, 13, 15, 16, 67.

[126] See FDA v. Brown & Williamson Tobacco Corp., 529 U.S. 120, 160 (2000).

[127] See West Virginia v. EPA, 597 U.S. at 746-47 (Gorsuch, J., concurring) (quoting Whitman v. Am. Trucking Ass’ns, 531 U.S. 457, 468 (2001)). 

[128] Id. at 700 (internal citations omitted).

[129] Certification of New Interstate Nat. Gas Facilities, 178 FERC ¶ 61,107 (2022) (Christie, Comm’r, dissenting at P 22-23 (quoting Nat’l Fed’n of Indep. Bus. v. Dep’t of Labor, OSHA, 595 U.S. 109, 121-22 (2022) (Gorsuch, J., concurring); In re MCP No. 165, 20 F.4th 264, 267-68 (6th Cir. 2021) (Sutton, C.J., dissenting (emphases added))) (internal citations omitted) (Certificate Dissent), https://www.ferc.gov/news-events/news/items-c-1-and-c-2-commissioner-christies-dissent-certificate-policy-and-interim.

[130] See Brad Plumer, Energy Dept. Aims to Speed Up Permits for Power Lines, The New York Times, Apr. 25, 2024 (quoting Rob Gramlich, the president of the consulting group Grid Strategies, “‘I’ve called [the final] rule the biggest energy policy in the country.’” (emphasis added)), https://www.nytimes.com/2024/04/25/climate/energy-dept-speed-transmission.html.

[131] Final Rule, 187 FERC ¶ 61,068 at P 275.

[132] Id.

[133] Id. P 277.

[134] Id.

[135] Id. P 278 (quoting West Virginia v. EPA, 597 U.S. at 735 (J. Gorsuch, concurring)). 

[136] See supra Section III.B.  Since 2005, FERC has had very limited backstop siting authority for certain transmission projects that has never been used.  See generally Applications for Permits to Site Interstate Elec. Transmission Facilities, Order No. 1977, 187 FERC ¶ 61,069 (2024).

[137] Final Rule, 187 FERC ¶ 61,068 at P 86 & n.184 (emphasis added) (citing South Carolina, 762 F.3d at 55-59, 84 (affirming the Commission’s authority to regulate transmission planning and cost allocation as practices affecting rates); Order No. 1000-A, 139 FERC ¶ 61,132 at P 577 (holding that “requirements regarding transmission planning and cost allocation . . . are practices affecting rates.”)); see also id. P 130 (“Instead, because practices directly affecting Commission-jurisdictional rates, terms, and conditions of service for interstate transmission and wholesale electricity are the exclusive jurisdiction of the Commission, we must ensure that Commission-jurisdictional processes associated with regional transmission planning and cost allocation result in rates that are just and reasonable and not unduly discriminatory or preferential.”) (emphasis added); id. P 770.

[138] See, e.g., South Carolina, 762 F.3d at 62 n.3.

[139] See FERC v. Elec. Power Supply Ass’n, 577 U.S. 260, 281 (2016) (“It is a fact of economic life that the wholesale and retail markets in electricity, as in every other known product, are not hermetically sealed from each other.  To the contrary, transactions that occur on the wholesale market have natural consequences at the retail level.”).

[140] See Silkwood v. Kerr-McGee Corp., 464 U.S. 238, 248 (1984) (“If Congress evidences an intent to occupy a given field, any state law falling within that field is preempted.” (citation omitted)); PPL EnergyPlus, LLC v. Nazarian, 753 F.3d 467, 475-476 (4th Cir. 2014) (“Even where state regulation operates within its own field, it may not intrude indirectly on areas of exclusive federal authority.” (quoting Pub. Utils. Comm’n of State of Cal. v. FERC, 900 F.2d 269, 274 n.2 (D.C. Cir.1990) (internal quotation marks omitted))).

[141] The final rule’s determination here aligns with the final rule’s complete gutting of the roles of the states in transmission planning and cost allocation.  See infra Section IV.B.1.

[142] 16 U.S.C. 824e.

[143] See South Carolina, 762 F.3d at 64-65 (citations omitted).

[144] Id. at 54 (quoting Wis. Gas Co. v. FERC, 770 F.2d 1114, 1156) (alterations in the original)).

[145] See Final Rule, 187 FERC ¶ 61,068 at P 132 (citing South Carolina, 762 F.3d at 67) (additional citation omitted).

[146] Id. P 111.

[147] Id. PP 90-91.

[148] Id. P 90.

[149] Id. P 92.

[150] Id. P 95.

[151] Id. PP 93-94.

[152] Id. PP 96-97.

[153] See, e.g., Johannes Pfeifenberger, et al., The Brattle Group and Grid Strategies, Transmission Planning for the 21st Century: Proven Practices that Increase Value and Reduce Costs, at 48-49 (Oct. 2021), https://www.brattle.com/wp-content/uploads/2021/10/2021-10-12-Brattle-GridStrategies-Transmission-Planning-Report_v2.pdf; Rob Gramlich and Jay Caspary, Americans for a Clean Energy Grid, Planning for the Future: FERC’s Opportunity to Spur More Cost-Effective Transmission Infrastructure, at 26-28 (Jan. 2021), https://cleanenergygrid.org/wp-content/uploads/2021/01/ACEG_Planning-for-the-Future1.pdf; Johannes P. Pfeifenberger, et al., The Brattle Group, Cost Savings Offered by Competition in Electric Transmission: Experience to Date and the Potential for Additional Customer Value (Apr. 2019), https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf.

[154] Such commenters include ACORE, PIOs, ACEG, Advanced Energy Buyers, AEE, Renewable Northwest, SREA, and Clean Energy Buyers.

[155] See Final Rule, 187 FERC ¶ 61,068 at P 96.

[156] Id. P 101.

[157] Id.

[158] See South Carolina, 762 F.3d at 67 (quoting Associated Gas Distribs. V. FERC, 824 F.2d 981, 1019 (D.C. Cir. 1987)) (alteration in the original).

[159] See generally Final Rule, 187 FERC ¶ 61,068 at PP 71-77.

[160] Id. P 102; see OMS Initial Comments at 2 (stating that “it is critically important to note at the outset that MISO’s regional planning process already reflects many of the elements and features contained in the [NOPR], and it should be looked to as a model for other regions to emulate.”); MISO Initial Comments at 1-2.

[161] CAISO Initial Comments at 3 (“The CAISO already engages in long-term planning, and its existing transmission planning process is consistent with the direction of the NOPR.”); CAISO Reply Comments at 1-2 (stating that “the Commission should not unduly disrupt or undo existing planning processes and approaches that are functioning well and enabling transmission providers to plan for system needs efficiently and cost-effectively.”).

[162] New York Commission and NYSERDA Initial Comments at 5.

[163] See, e.g., Southern Companies Initial Comments at 13-15 (stating that its “IRP/RFP-driven transmission planning is successfully expanding their electric grid to address the changing resource mix and load”); Undersigned States Reply Comments at 6-7.

[164] NRECA Initial Comments at 14-16.

[165] NOPR Concurrence at P 5 (emphases in original) (footnote omitted). 

[166] Id. P 11 (emphases in original) (footnotes omitted).

[167] Id. P 14 (emphasis in original).

[168] See supra n.48; NOPR, 179 FERC ¶ 61,028 (Phillips, Comm’r, concurring at P 4) (“I support the proposal to require transmission providers to consult with and incorporate states’ views in project selection and cost allocation.  I invite comment on the value of such state involvement for increasing the likelihood that those facilities are sited and ultimately developed with fewer costly delays.”), https://www.ferc.gov/news-events/news/item-e-1-commissioner-phillips-concurrence-building-future-through-electric.

[169] See supra Section III.C.

[170] NOPR Concurrence at P 13 (emphasis in original).

[171] NOPR, 179 FERC ¶ 61,028 at P 244; see also NOPR Concurrence at P 11 (“State approval is especially important in a multi-state region, where different states have different policies.  The NOPR proposes to provide the maximum opportunity for creativity and flexibility to the states and regional entities in developing the process for designing and approving regional selection criteria and cost allocation arrangements.”).

[172] NOPR, 179 FERC ¶ 61,028 at P 246.

[173] See NOPR Concurrence at P 11; see also supra n.48.

[174] Final Rule, 187 FERC ¶ 61,068 at P 996 (emphases added). 

[175] Id. P 999.

[176] Id. P 962 (emphasis added).

[177] Id. P 996.

[178] Id.

[179] See supra P 69.

[180] See supra Section I.  Another example, of course, is micromanaging how local “stakeholder” meetings must be conducted, which, as noted, runs a strong risk of conflicting with state IRP proceedings and state authority.  See Final Rule, 187 FERC ¶ 61,068 at PP 1625-1646.  As above, I question whether prescriptive requirements to this degree can truly pass muster under court precedent.

[181] And transmission providers themselves cannot even voluntarily account for states’ input in the planning.  Today’s final rule requires that transmission providers may not include in their evaluation process or selection criteria any prohibition on the selection of a Long-Term Regional Transmission Facility based on the transmission providers’ anticipated response of a state public utility commission or consumer advocates to particular Long-Term Regional Transmission Facilities.  Final Rule, 187 FERC ¶ 61,068 at P 962.

[182] I am aware that states qua states do not join RTOs/ISOs.  Rather, they use their regulatory power to allow or require their regulated transmission-owning utilities to join.

[183] NOPR Concurrence at P 13.

[184] Commonwealth of Virginia, ex rel. State Corporation Commission, Ex Parte: In the matter concerning the application of Virginia Electric and Power Company d/b/a Dominion Virginia Power for approval of a plan to transfer functional and operational control of certain transmission facilities to a regional transmission entity, Case No. PUE-2000-00551 (Nov. 10, 2004).  The order included a stipulation in which Dominion agreed that joining PJM would not alter its legal obligation to seek a CPCN from the Virginia Commission to construct generation or transmission assets.  Id., Partial Stip. ¶ 6.

[185] NARUC Initial Comments at 45. 

[186] Id. at 46 (citations omitted).

[187] NOPR, 179 FERC ¶ 61,028 at P 302.

[188] Final Rule, 187 FERC ¶ 61,068 at P 1291.

[189] Id. PP 1292, 1361, 1404.

[190] Id. P 1292.

[191] Id. P 1293.

[192] Id. P 1354.

[193] Id. P 1357.

[194] Id. P 1367.

[195] E.g., id. P 1359 (“[T]he ultimate decision as to whether to file a Long-Term Regional Transmission Cost Allocation Method(s) and/or State Agreement Process to which Relevant State Entities have agreed will continue to lie with the transmission providers.”); id. P 1429 (“[A]fter the required Engagement Period, transmission providers in each transmission planning region will decide what Long-Term Regional Transmission Cost Allocation Method(s) and any State Agreement Process to file as part of their compliance filings.  Therefore, transmission providers in a transmission planning region could elect to propose on compliance a Long-Term Regional Transmission Cost Allocation Method and not file a State Agreement Process or other ex ante cost allocation method to which Relevant State Entities agreed.  In addition, we do not impose any obligation on transmission providers to file a cost allocation method for Long-Term Regional Transmission Facilities with which they disagree, even if such a method were proposed to the transmission providers pursuant to a Commission-approved State Agreement Process, unless the transmission providers have clearly indicated their assent to do so as part of a Commission-approved State Agreement Process in their OATTs.”) (emphases added; footnote omitted); see also id. P 1356 n.2895 (citing Atl. City Elec. Co. v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002) (Atlantic City)).

[196] NARUC Initial Comments at 49.

[197] Final Rule, 187 FERC ¶ 61,068 at P 1368.

[198] Id.

[199] See NARUC Initial Comments at 45 (“NARUC strongly supports the Commission’s proposal to involve states in cost allocation for Long-Term Regional Transmission Facilities and conversely explicitly rejects a requirement that public utility transmission providers include a Long-Term Regional Transmission Cost Allocation Method in their OATTs without being obligated to seek agreement from relevant state entities.”) (footnotes omitted); see, e.g., Alabama Commission Initial Comments at 9 (“In other words, states may not force their preferences on their neighbors, or compel them to subsidize their achievement.  Thus, it goes without saying that Alabama ratepayers should not be required to pay for transmission projects that are designed to promote or facilitate the public goals of other states, localities, or entities.”); West Virginia Commission Reply Comments at 2-3 (“The [West Virginia Commission] opposes any changes in transmission cost allocation that would require West Virginia customers, or customers of any State, to involuntarily pay for new transmission facilities that are needed to support the public policy generation choices of other States.”); North Carolina Commission and Staff Initial Comments at 15-16 (“The [North Carolina Commission and Staff] strongly support the NOPR proposals regarding cost allocation for regional transmission facilities developed through the Long-Term Regional Transmission Planning process, as that term is defined in the NOPR, specifically the requirement for transmission providers to seek state agreement on cost allocation methodologies and the requirement to create an opportunity for states to negotiate a cost allocation method after a transmission facility has been selected through the Long-Term Regional Transmission Planning process.”); Utah Commission Initial Comments at 9 (“[I]mposing a single set of federally mandated, highly prescriptive transmission planning and cost allocation requirements for the purpose of privileging the selection of costly transmission projects to serve remote and speculative renewable generation is not a lawful exercise of FERC’s authority under Section 206.”).

[200] NARUC Initial Comments at 51 (footnote omitted).

[201] PJM’s State Agreement Approach exemplified the proper way to involve states in decisions regarding cost allocation for public policy projects.  The PJM State Agreement Approach was not directed by Order No. 1000, but rather by PJM’s own voluntary act of reaching out to the states in PJM States and asking PJM States to propose a cost allocation for public policy projects.  PJM accepted PJM States’ proposal—which became the PJM State Agreement Approach—and submitted it to FERC in its compliance filing.  It was accepted by FERC, but as today’s final rule shows, only grudgingly and only until the chance came to extinguish it.

[202] NARUC Initial Comments at 46 (citing MISO Transmission Owners Agreement, Appendix K, Article II, Section II.E.3.b (providing regional state committee with the opportunity to develop and request MISO file an alternative cost-allocation methodology under certain circumstances); ISO New England, Agreements and Contracts, Transmission Operating Agreement, Section 3.04 (h)(vi)(A-C) (providing regional state committee with opportunity to provide alternative cost allocation proposal in connection with certain transmission cost allocation provisions in ISO-NE’s tariff)). 

[203] See SPP, Governing Documents Tariff, § 7.2 (Bylaws 7.2 Regional State Committee) (2.0.0); see also Sw. Power Pool, Inc., 106 FERC ¶ 61,110, at P 219, order on reh’g, 109 FERC ¶ 61,010, at PP 93-94 (2004); Entergy Arkansas, Inc., 133 FERC ¶ 61,211, at P 15 (2010).

[204] E.g., Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ¶ 61,165, at PP 30-31 (2013) (citations omitted).

[205] See, e.g., Final Rule, 187 FERC ¶ 61,068 at PP 1359, 1429; see also id. P 1356 n.2895 (citation omitted).

[206] See, e.g., id. P 1412 (“[N]or do we create any obligation that transmission providers file a cost allocation method resulting from a State Agreement Process, unless the transmission providers had clearly indicated assent to do so in their OATTs); id. n.3013 (“[T]ransmission providers may voluntarily agree as part of a State Agreement Process in their OATTs that transmission providers shall file any cost allocation method that meets the requirements of their State Agreement Process, even if those transmission providers do not agree with that method.”).

[207] Id. P 124.

[208] 295 F.3d 1.

[209] E.g., Final Rule, 187 FERC ¶ 61,068 at P 1363 & n.2909; id. P 1356 n.2895.

[210] Id. P 1293. 

[211] 295 F.3d at 9-11.

[212] See also Peskoe Article at 572 (emphasis added), a thorough and helpful distillation of the intricacies of FPA sections 205 and 206 as to RTO governance.  See also id. at 567.

[213] See id. at 614-615 (“To bolster RTO independence, FERC could expand filing rights over regionally significant issues that are currently controlled by the [investor-owned utilities (IOUs)], such as cost allocation for regional transmission expansion. . . .  State regulators are also potential beneficiaries.  State utility commissions comprehensively regulate IOUs’ local service and are familiar with IOUs’ local operations and planning.  State filing rights might serve a consumer protection function, as state regulators are ultimately responsible for ensuring that retail rates, which include costs of RTO-planned transmission projects and RTO-administered markets, appropriately account for consumers’ interests.  As noted, MISO and SPP agreements already provide state regulators with limited filing rights over transmission cost allocation or resource adequacy, two areas where states have overlapping oversight. . . .  Providing states with meaningful roles in RTO processes might mitigate future conflicts between states’ priorities and RTO rules and planning processes.”) (emphases added) (footnotes omitted).  Let me add my strong endorsement to granting states section 205 filing rights with respect to cost allocation.  The final rule, of course, goes in the opposite direction. 

[214] See e.g., Final Rule, 187 FERC ¶ 61,068 at PP 1356 n.2895, 1429-1431.

[215] Id. P 1293.

[216] NOPR Concurrence at P 12 (citing NOPR, 179 FERC ¶ 61,028 at PP 302, 312).

[217] N.Y. Power Auth., 185 FERC ¶ 61,102 (2023) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-nypas-abandoned-plant-incentive-el23; N.Y. Indep. Sys. Operator, Inc., 180 FERC ¶ 61,004 (2022) (Christie, Comm’r, concurring at P 2).

[218] E.g., N.Y. Indep. Sys. Operator, Inc., 178 FERC ¶ 61,101 (2022) (Christie, Comm’r, concurring at P 5), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-independent.

[219] N.Y. Indep. Sys. Operator, Inc., 186 FERC ¶ 61,184 (2024) (Christie, Comm’r, concurring at P 2).

[220] NSTAR Elec Co., 179 FERC ¶ 61,200 (2022) (Christie, Comm’r, concurring at P 10), https://www.ferc.gov/media/e-13-er22-1247-000; see also N.Y. Indep. Sys. Operator, Inc., 178 FERC ¶ 61,101 (Christie, Comm’r, concurring at P 6) (“A similar analysis could well lead to a different outcome in a multi-state RTO, if the record showed that the RTO was implementing one state’s public policies as to preferred resources, and that implementation resulted in impacts being shifted to consumers in one or more other states in the multi-state RTO.  Such impacts and cost-shifting in multi-state RTOs, if proven by the record, could well be unjust, unreasonable and unduly discriminatory or preferential under the FPA.”) (emphasis in the original and added); N.Y. Pub. Serv. Comm’n v. N.Y. Indep. Sys. Operator, Inc., 174 FERC ¶ 61,110 (2021) (Christie, Comm’r, concurring at P 3) (“I also note that the NYISO is a single-state ISO and I have been able to locate no evidence in the record that the New York policies at issue in today’s order are causing cost-shifting onto consumers in other states.  If consumers in other states were disadvantaged, I may well view this matter differently.”) (emphasis added), https://www.ferc.gov/news-events/news/item-e-2-commissioner-mark-c-christie-concurrence-regarding-new-york-state-public; cf. Commissioner Mark C. Christie, Fair RATES Act Statement on PJM Minimum Offer Price Rule (MOPR) Revisions, Docket No. ER21-2582-000 at P 6 (Oct. 19, 2021) (“I would have proposed that PJM formulate a replacement for the current MOPR based on three broad principles:  (1) a state may designate specific or categorical resources as ‘public policy resources’ and such designated resources will be funded through a mechanism chosen by the state outside of the capacity market . . . and (3) non-sponsoring state consumers would not be forced to pay for another state’s designated public-policy resources.”) (footnotes omitted) (emphasis in the original and added), https://www.ferc.gov/news-events/news/commissioner-christies-fair-rates-act-statement-pjm-mopr.

[221] Certificate Dissent at P 63.

[222] Infra Section IV.B.2.b.

[223] See, e.g., Final Rule, 187 FERC ¶ 61,068 at PP 266, 269, 279, 1304, 1478-1479.  

[224] As an aside, I question whether some of the precedent cited by today’s final rule in support of the cost causation issue is truly apposite when you look at the facts in those cases. 

[225] KN Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir. 1992) (emphasis added).

[226] 576 F.3d 470, 476 (7th Cir. 2009) (ICC).

[227] Id.

[228] Order No. 1000-A, 139 FERC ¶ 61,132 at P 573.

[229] Id. P 578.

[230] Id. P 560 (citations omitted).

[231] Id. P 562 (internal citation omitted).

[232] Id. P 565 (citing ICC, 576 F.3d 470 at 476) (alterations in the original).  In Order No. 1000, the Commission also found that “[b]eneficiaries in one state are not subsidizing anyone in another state when they are allocated costs that are commensurate with the benefits that accrue to them, even if the transmission facility in question was built in whole or part as a result of the other state’s transmission needs driven by Public Policy Requirements.”  Order No. 1000, 136 FERC ¶ 61,051 at P 545.  “If no benefits accrue, the cost allocation principles we adopt below would prohibit the allocation of costs to the non-beneficiaries.  If benefits do accrue, however, there are no less benefits because Public Policy Requirements played a role in the decision to construct the transmission facility.”  Id.  While Order No. 1000 may have successfully established this to be the case, per South Carolina, today’s final rule is not similarly situated to Order No. 1000 with its required minimum benefits, selection criteria, and utter disregard of the states’ role in planning and cost allocation.  See supra Section III.A.  Today’s final rule instead creates beneficiaries for projects that are primarily public policy-driven, based on the categories of factors required to be considered in today’s final rule’s planning requirements.

[233] 576 F.3d 470.

[234] See PATH Concurrence at P 4 (providing a history on Project Mountaineer).  Relying on a case that remanded the Commission’s approval of cost allocation associated with a regional transmission project that never came to fruition is nothing short of ironic.

[235] ICC, 576 F.3d at 476 (emphasis added). 

[236] Id. (emphasis added).  See NARUC Initial Comments at 33-34 (“Long-Term Regional Transmission Planning must recognize that benefits inherently become more speculative as the planning horizon increases.  Additionally, planning based on public policy objectives must be transparent about identifying projects that would not be selected but for those public policy objectives.  Benefits assigned to projects must recognize these principles.”) (emphasis added).

[237] See supra Sections I, III.A; see also Final Rule, 187 FERC ¶ 61,068 at P 965.

[238] Final Rule, 187 FERC ¶ 61,068 at P 1515.  This is why I have described this final rule as a shell game with respect to the issue of the benefit mismatch between planning and costs.  By making the minimum required benefits reliability- and economic-focused, today’s final rule ensures that the “beneficiaries” are those that are receiving some reliability and economic benefits.  As we know from basic transmission planning, any transmission built is going to bring some reliability and economic benefits.  So, any transmission planned through Long-Term Regional Transmission Planning for the identified Long-Term Transmission Needs will necessarily bring some reliability and economic benefits.  And by not requiring a matching of benefits to the Long-Term Transmission Needs that are planned for, in this case public policy benefits, the resulting benefits of any one project will be skewed to indicate more “beneficiaries” than there would be if today’s final rule accounted for public policy benefits separately.  See NARUC Initial Comments at 33-34.  If today’s final rule accounted for public policy benefits or corporate goals separately, it would be clear who the actual drivers, and actual beneficiaries, of any one project are. 

[239] 762 F.3d 41.

[240] Id. at 85.

[241] Id. (citations omitted).

[242] See supra Sections I, III.A.

[243] See South Carolina, 762 F.3d at 81; see also supra Section III.A.

[244] See, e.g., Final Rule, 187 FERC ¶ 61,068 at P 1506 (“We do not require that any particular benefit used in the evaluation and selection of Long-Term Regional Transmission Facilities be reflected in a Long-Term Regional Transmission Cost Allocation Method filed with the Commission.”).  This provision illustrates the confusing and contradictory nature of the final rule and provides another example of the shell game.

[245] Today’s final rule relies on several other cases in support of its oversimplification of the cost causation principle, such as Old Dominion Electric Coop. v. FERC, 898 F.3d 1254 (D.C. Cir. 2018), and Long Island Power Authority v. FERC, 27 F.4th 705 (D.C. Cir. 2022), among others, but the same is true of these cases—the Commission cannot strong-arm beneficiaries to get transmission built, and override the states to do so.  Of course, this is primarily a problem in multi-state RTOs, but overriding the states with regulation based on a cooperative federalism statute is not in good faith and the result is terrible for consumers everywhere.

[246] See supra Section IV.A.

[247] See Final Rule, 187 FERC ¶ 61,068 at P 1474.

[248] See NARUC Comments at 25; see also New York Commission and NYSERDA Initial Comments at 7 (“We urge the Commission to ensure that any final rule in this proceeding is sufficiently flexible to accommodate regional differences and avoid disrupting the processes already in place and otherwise underway in New York that are working well for the region.”); SPP Initial Comments at 18 (“How and when transmission benefits are calculated and incorporated in any regional transmission planning assessment should be at the discretion of each public utility transmission provider and its stakeholders. This would allow for agility in process decisions to balance the value the analysis provides with the burden of the effort.”); ISO-NE Initial Comments at 5 (“Individual regions should be permitted to determine the benefits that will lead to transmission in the region.”); NYISO Initial Comments at 39 (“The final rule should confirm that each planning region is not required to use the specific benefits described in the NOPR . . . . While, in practice, the NYISO already uses most of the 12 illustrative benefits identified in the NOPR, the NYISO should be permitted to retain its flexibility to identify, with input from state entities and stakeholders, the benefits used in its processes and how such benefits are calculated.”); id. at 11 (“The final rule should not mandate strict requirements concerning how long-term transmission planning must be conducted.”).

[249] Final Rule, 187 FERC ¶ 61,068 at Section III.D.1.c.

[250] See Midcontinent Indep. Sys. Operator, Inc., 184 FERC ¶ 61,190 (2023) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-order-concerning-funding; Midcontinent Indep. Sys. Operator, Inc., 184 FERC ¶ 61,156 (2023) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-gia-order-concerning-funding; Midcontinent Indep. Sys. Operator, Inc., 183 FERC ¶ 61,113 (2023) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-fsa-order-concerning-funding; Midcontinent Independent System Operator, Inc., 182 FERC ¶ 61,225 (2023) (Christie, Comm’r, concurring at P 2), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-miso-mpfca-and-fsa-orders-concerning-funding; see also Midcontinent Indep. Sys. Operator, Inc., 185 FERC ¶ 61,182 (2023), order on reh’g, 187 FERC ¶ 61,015 (2024), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-order-rejecting-miso-gia-concerning-funding.  This principle also applies to developers of merchant transmission lines who seek to interconnect.  Midcontinent Indep. Sys. Operator, Inc., 181 FERC ¶ 61,218 (2022) (Christie, Comm’r, concurring at P 1), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-concerning-funding-interconnection-costs-rtos.  If state regulators in a multi-state region agreed on a different cost allocation related to interconnection costs that they believed protected consumers from unfair treatment, then such alternative would merit consideration.

[251] Final Rule, 187 FERC ¶ 61,068 at PP 1106-1107, 1126, 1145.  Specifically, the final rule requires transmission providers to evaluate for selection regional transmission facilities to address interconnection-related transmission needs that have been identified in the generator interconnection process as requiring interconnection-related network upgrades where, inter alia, “an interconnection-related network upgrade identified to meet those interconnection-related transmission needs has a voltage of at least 200 kV and an estimated cost of at least $30 million.”  Id. P 1145 (emphasis in original).

[252] Id. P 1110.

[253] Id.

[254] Id. (footnote omitted).

[255] Id. PP 1146-1148.

[256] See id. P 1117.

[257] Id.

[258] Id.; see also id. P 1110.

[259] See id. PP 1119-1120.

[260] Id. P 1119.

[261] See, e.g., Order No. 2023, 184 FERC ¶ 61,054 at P 47 (stating that the existing serial first-come, first-served study process “create[d] incentives for interconnection customers to submit exploratory or speculative interconnection requests pursuant to which interconnection customers seek to secure valuable queue positions as early as possible, even if they are not prepared to move forward with the proposed generating facility.  Such generating facilities are often not commercially viable and, thus, the interconnection customers ultimately withdraw from the interconnection queue.”).

[262] See Final Rule, 187 FERC ¶ 61,068 at P 472. 

[263] Id. PP 481-484.

[264] Id. P 484.

[265] Commenters in favor include ACEG, AEE, Advanced Energy Buyers, Amazon, Breakthrough Energy, Center for Biological Diversity, Environmental Groups, Ørsted, PIOs, SEIA, and SREA.  Id. PP 474-476.  Commenters expressing qualified support include LADWP, MISO, and NRECA.  Id. P 477.  Commenters opposed include the Alabama Commission, California Commission, Duke, Illinois Commission, New York TOs, Pennsylvania Commission, PJM, and PPL.  Id. PP 478-480.

[266] See James Downing, FERC Observers, Stakeholders Lay out What is at Stake with Tx Rule Looming, RTO Insider, Apr. 22, 2024 (“State renewable portfolio standards are not driving as much of the need for new transmission as the corporate renewable energy buyers that [Clean Energy Buyers] represents are, [Clean Energy Buyers Senior Director Bryn Baker] added.”), https://www.rtoinsider.com/76831-ferc-experts-what-at-stake-transmission-rule-looming/.

[267] For a reminder on the shell game and how it seeks to use the cost causation principle, see supra Sections I, III.A, IV.B.2.b.

[268] Final Rule, 187 FERC ¶ 61,068 at P 484.

[269] I also have grave concerns that the final rule tasks transmission planning engineers to try their hands at becoming Wall Street analysts when they attempt to guess how serious any of the corporate commitments really are.

[270] Promoting Transmission Inv. through Pricing Reform, Order No. 679, 116 FERC ¶ 61,057, at PP 26, 117, order on reh’g, Order No. 679-A, 117 FERC ¶ 61,345 (2006), order on reh’g, 119 FERC ¶ 61,062 (2007).

[271] See supra n.61.

[272] February 2022 Concurrence at P 3 (emphasis in original); July 2022 Concurrence at P 3 (citation omitted); see also NOPR Concurrence at P 15 (“CWIP is, of course, passed through as a cost to consumers, making consumers effectively an involuntary lender to the developer . . . .  Consumers should be protected from paying CWIP costs during this potentially long period before a project actually enters service, if it ever does.”), https://www.ferc.gov/news-events/news/commissioner-christies-concurrence-e-1-regional-transmission-planning-and-cost.    

[273] See supra PP 18-19.

[274] Final Rule, 187 FERC ¶ 61,068 at P 1547.

[275] See, e.g., California Commission Reply Comments at 14; Kentucky Commission Chair Chandler Initial Comments at 4-9; NARUC Initial Comments at 55-56 (referencing PATH and that the Commission granted several transmission incentives, resulting in a 14.3% return on equity); NASUCA Initial Comments at 8-9; North Carolina Commission and Staff Initial Comments at 17-18; North Dakota Commission Initial Comments at 6; Ohio Commission Federal Advocate Initial Comments at 15-16; Ohio Consumers Initial Comments at 29-31; OMS Initial Comments at 14-15; Pennsylvania Commission Initial Comments at 17-18; PJM States Initial Comments at 13; Virginia Attorney General Reply Comments at 3-4.

[276] See, e.g., Massachusetts Attorney General Initial Comments at 24-25; North Carolina Commission and Staff Initial Comments at 17-18; Pennsylvania Commission Initial Comments at 17-18; PJM States Initial Comments at 13.

[277] See, e.g., Baltimore Gas & Elec. Co., 187 FERC ¶ 61,030 (Christie, Comm’r, dissenting at P 6).

[278] To reiterate what I said earlier:  If I agree to get a root canal with anesthetic but learn upon arrival at the dentist’s office that I still get the root canal but no anesthetic, that is not the original deal.

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