Assessing Electric Transmission’s Cost Allocation Dilemma

Audio Brief

A short, spoken-word summary from CSIS’s Cy McGeady on his commentary “Assessing Electric Transmission’s Cost Allocation Dilemma.” 

Audio file

Transmission is suddenly in the limelight. Without it, the United States will be unable to deploy the vast amount of wind and solar power generation projects that the Inflation Reduction Act makes economically viable, and that is needed to decarbonize the U.S. power system in line with the administration’s stated targets.

Permitting and siting reform have risen to the top of the agenda because they are a key bottleneck for transmission projects. The linear and long-distance nature of transmission infrastructure means these projects cross numerous jurisdictions and permitting regimes; these include National Environmental Policy Act (NEPA) environmental reviews, agencies like Army Corp of Engineers and Bureau of Land Management, and permits under Clean Water Act and Endangered Species Act, which can be issued at the state and federal level. The 17-year permitting of the SunZia transmission line project between New Mexico and Arizona is a case study in how difficult permitting and siting can be.

Cost Is the Real Problem

Unfortunately, permitting is only part of the challenge for transmission. The other major issue is cost, and by extension, the planning regimes that allocate cost. The high-voltage transmission systems the United States needs to build are expensive. For example, a single roughly 60-mile high-voltage transmission project in North Dakota, recently approved by the Midcontinent Independent System Operator (MISO), will cost nearly $500 million. The Net-Zero America report, published by the Princeton University. models $2.2 trillion in transmission investments by 2050 in its base net-zero scenario.

In Congress, the high cost, and the method by which these costs are distributed to ratepayers, most divides opinions on transmission policy. Two recent letters to Federal Energy Regulatory Commission (FERC), penned by senators on opposing sides of the aisle, illustrate this divide. Senator Chuck Schumer (D-NY) wants FERC to mandate that regions plan transmission systems with high renewable energy deployment scenarios in mind and firmly define broad criteria for allocating transmission project costs. Conversely, Senator Kevin Cramer (R-ND), writes that “regulators could just as easily use an arbitrary and loosely defined set of ‘benefits’ to socialize costs across a broader rate base.” Because states retain jurisdiction over ratemaking and the generation mix, the latter letter insists FERC reinforce the “fundamental principle [of] states’ responsibility to foot the bill associated with their decisions.” These perspectives hinge on the question of who pays for the transmission system expansion that is required over the coming decades.

Defining Cost Allocation

The cost of building and maintaining the electrical grid is always ultimately paid by the end consumer. This may arrive as a direct line item on the ratepayer bill, or in the form of higher per unit energy rates. At the local level, the local utility—be it an investor-owned utility, a municipal or government entity, or an electric cooperative—assesses the requirement for repairs, maintenance, and new power lines, and submits these proposed investments to the state public utilities commission, which then reviews and approves these costs as part of the rate paid by electricity consumers. This process generally works neatly for distribution system poles and wires and the smaller-scale local transmission projects.

Across the United States, investment into local transmission and distribution systems is healthy and growing. Unfortunately, this may be occurring to the detriment of more efficient investment in large-scale transmission projects. Those projects are far more difficult to execute because they can cross multiple jurisdictions, utility systems, market operator borders, transmission planning regions, and the regulatory boundaries of state public utilities commission.

In 2011, FERC issued Order No. 1000, which sought to standardize and smooth the regional transmission planning process. The rule required designated planning regions and required them to conduct regular and open regional planning processes, and likewise develop interregional planning procedures with neighboring regions. Importantly, for projects developed and selected under these processes, FERC required defined cost allocation measures and eliminated the right of first refusal for incumbent transmission owners.

A counterintuitive effect of Order No. 1000 is that these same processes and rules act as disincentives for various participants to advance high-voltage transmission projects. They must endure the scrutiny of regional planning, diverse stakeholder intervention opportunities, and are subject to contentious regional cost allocation and solicitation procedures. This effect is demonstrated by analysis from Rocky Mountain Institute which shows local transmission spending in PJM has grown to represent 71 percent of total spending since 2014 (the year following Order No. 1000 tariff implementation) compared to 26 percent prior. In total, Order No. 1000 can be said to have failed to significantly improve prospects for large-scale high-voltage transmission projects, a result which motivates FERCs latest proposed transmission rule.

Survey of Transmission Project Cost Allocation Methods

Despite this, some transmission projects are proceeding. Below is an inexhaustive selection of high-voltage transmission projects that have begun construction or have secured cost recovery and are nearing construction. The focus of each is to understand who is paying for the project and what process determined this result.

  1. New England Clean Energy Corridor: This project, known as the NECEC, seeks to connect hydropower generated in Quebec to Massachusetts. To do roughly 150 miles of new high voltage, transmission lines will be built in Maine allowing power to flow into the New England power market. The project is developed by Avangrid, paid for by the regulated electric utilities of Massachusetts, who in turn are acting under a state legislative mandate to procure large volumes of renewable energy. Accordingly, this project is funded exclusively by Massachusetts ratepayers, though the actual investments are entirely out of state. Federal cost allocation is not relevant to a project such as this because it is planned, procured, and paid for by a single state.
  1. Champlain Hudson Power Express (CHPE): This direct current (DC) project will run north to south through New York state, mostly running under Lake Champlain and the Hudson River, delivering Canadian-produced power to New York City. The merchant project is developed by a private company and proposed to state regulatory authorities. The private developer will receive revenues to cover its costs from a state agency, NYSERDA, through issuance of Clean Energy Standard certificates. Again, in this case, FERC-regulated regional transmission planning and cost allocation is not relevant as the project is entirely within state borders; NY ratepayers fund NYSERDA and therefore will indirectly pay for the entire project.
  1. MISO Tranche 1 Project Portfolio: In May of 2022, FERC issued an order accepting tariff revisions that would allow MISO to proceed with a roughly $10 billion of 18 transmission projects across the MISO Midwest Region. The projects will create new 345-kilovolt (kV) paths allowing more efficient power flow west to east and north to south through the region that stretches from North Dakota through Illinois and into Michigan. The cost of these projects will be allocated across all ratepayers in all utilities that make up the MISO Midwest region on a postage stamp basis. This method allocates cost according to each utility based on their share of total regional electric load. The simplicity of this method is attractive, and for projects that impact and bring benefits to the entire region, it falls within FERCs requirement that costs be allocated roughly commensurate with benefits. However, the process does not satisfy all stakeholders; many utilities within MISO argue that they pay too much. Meanwhile some state policymakers fear their ratepayers are paying for transmission that unlocks wind power projects needed for other state’s policy goals.
  1. PacifiCorp Energy Gateway: This portfolio of projects is developed by PacifiCorp, a vertically integrated investor-owned utility that operates across various states in the western U.S. outside of the ISO/RTO framework. The 2,300 miles of high-voltage AC lines will stretch across state lines but remain entirely within the footprint of PacifiCorp’s local subsidiary utility companies (e.g., Rocky Mountain Power in Wyoming, Utah, and Idaho). The multibillion-dollar project costs will be recovered through charges to ratepayers as approved by the respective state utility commissions in Wyoming, Utah, and Idaho. However, PacifiCorp could have elected to pursue Order No. 1000 regional cost allocation given that the 2022–23 transmission plan for the region identifies the Energy Gateway projects as resolving the transmission requirements for the entire region.
  1. SunZia: This project will deliver wind power produced in New Mexico to load centers in Arizona and Southern California via is a new 550-mile high-voltage direct-current (HVDC) line. Permitting for this project has taken 17 years to complete, but as of May 2023 the project is finally poised to begin As a merchant transmission project, the private developer and owner, Pattern Energy, will cover the costs of the project through privately negotiated contracts with demand side counterparties. Comments from the project’s developer indicate the project will “collect revenues from the customers purchasing the wind energy delivered by SunZia through power purchase agreements (PPAs) . . . Through this model the costs of new build transmission are borne by the specific customers reaping the benefits of the wind energy deliveries, most of whom being California load-serving entities (LSEs) conducting competitive solicitations.” Here again, FERC-regulated cost allocation is not relevant because of this privately sourced and negotiated funding.



These example projects (or project portfolios) are diverse; developed under different regulatory and legislative directives, developed by different types of commercial entities, and deploying different technologies. But each of these examples adds critical new transmission capacity to the grid and makes a significant contribution to the central strategic objective of a reliable and efficient U.S. electric system. What principles can be derived from these examples?

  1. Cost recovery is not the same thing as cost allocation. Many of these projects bypass FERC regulated regional cost allocation entirely. Other options include using merchant revenues (SunZia), state agencies (e.g., NYSERDA), or the traditional rate-base (Energy Gateway) to fund projects. This fact suggests that regional cost allocation may not be the only way to deliver large-scale transmission projects.
  1. States with ambitious renewable energy goals have demonstrated a willingness to directly pay for the transmission requirements implied by their goals. The New York, Massachusetts, and California cases point to this. The former two represent direct outlays mandated by state policy. In the case of SunZia, this outlay is voluntary and distributed across individual buyers (like the University of California System). However, these examples all involve HVDC technology, which allows direct point-to-point transmission service. Inevitably, high-voltage AC projects will be necessary to expand existing AC transmission networks; these may be harder to fund through direct state outlays.
  1. Transmission is fundamentally linked to generation. The Massachusetts NECEC and New York CHPE projects are directly tied to the movement of Canadian hydropower south into the East Coast load centers. The SunZia project is directly tied to the largest of wind power project in U.S. history. In the case of the MISO Tranche 1 and Energy Gateway project portfolios, the planning data suggests a wide range of benefits to the respective regions; but these benefits and the power flows are fundamentally linked to vast expansion of wind power underway in these regions.
  1. This pattern demonstrates that transmission requirements are downstream of generation policy choices, a result in line with key historic examples as well. The 500 kV transmission backbone in the Southeast is tied to nuclear power projects built by the TVA Tennessee Valley Authority and Entergy. The 765 kV transmission system in the Midwest was by American Electric Power (AEP) in part to move the power created by its coal power plants with record-breaking capacity for that time. The Pacific Intertie, a roughly 940-mile-long power line system stretching the length of the West Coast, was built to move hydropower from the Pacific Northwest into the load centers of Southern California.

    High-voltage transmission always provides diverse benefits, including reliability and economic benefits, because of the basic networked nature of the power grid. But the primary impetus for transmission expansion is in response to a changing and expanding generation resource mix.
  2. The benefits of high-voltage transmission are always mismatched to cost allocation. Each of the examined projects will inevitably bring benefits to a wider set of end users than those who pay for the project. The NECEC and CHPE HVDC projects will bring new low-cost power into the northeast power grid and provide reliability and economic benefits to ratepayers outside of Massachusetts and New York, respectively.

    While MISO’s Tranche 1 project portfolio is the best expression of the intent of Order No. 1000, the project portfolio is developed within regional limits; the projects are not developed to expand ties and transfer capabilities between neighboring power markets, notably the Southwest Power Pool (SPP) to the west, which hosts a vast fleet of wind power projects that needs to flow to load centers in MISO. Despite this, MISO has identified that SPP will in fact receive some benefits despite not sharing in cost allocation.

    It is clear from the regional transmission plan that the Energy Gateway projects will deliver a broad set of benefits to the entire region despite each state paying for the specific segments it hosts. Furthermore, the Energy Gateway projects will improve delivery of wind power into the California power market, bringing benefits to end users in California despite their shouldering no portion of the cost.


Paths Forward Recognize the Role of State Generation Policy

Two basic realities set the landscape for the transmission policy debate. First, federal energy policy continues to operate under the principles of the Federal Power Act in which states retain policy jurisdiction over their respective generation resource mix. Second, the expansion and design of the transmission system is inextricably linked to generation resource mix policy choices.

Expansion of the transmission grid is necessary in all conceivable policy pathways—this much is true. But the scale, location, and distribution of costs associated with this buildout is inextricably tied to generation mix policy choices that reside in the hands of the state lawmakers. Developing federal policy that reflects this reality may be the best way to reignite legislative prospects.

Cy McGeady is an associate fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.

Fellow, Energy Security and Climate Change Program