There is a broad consensus that the U.S. needs new electric transmission infrastructure to accommodate an evolving supply resource mix, facilitate growing electrification, and replace aging infrastructure. Getting the right transmission built will require smart planning and cooperation among industry stakeholders, including utilities, state and federal policymakers, transmission developers, public interest groups, and transmission customers. It will also be costly. It is essential to ensure that customers receive adequate value in exchange for their transmission dollars.
Unfortunately, the Federal Energy Regulatory Commission (FERC), the federal agency with broad authority over electric transmission facilities and utility transmission rates, is currently considering changes to its rules for awarding transmission rate incentives under section 219 of the Federal Power Act (FPA) that are unlikely to promote beneficial transmission projects at reasonable cost. The proposed revisions to FERC's regulations, if adopted, are likely to increase transmission revenues for investor-owned utilities without ensuring corresponding benefits for consumers.
The Case for New Incentives Is Lacking
There is no compelling reason for FERC to revisit its transmission incentive policies under section 219 of the FPA. That provision, which requires FERC to adopt certain rules for transmission incentives, was enacted in 2005 in response to a prolonged decline in transmission investment. Over the last decade or so, however, investment in electric transmission infrastructure has increased dramatically. Competitive transmission developers strive for the opportunity to build projects, while incumbent transmission owners vigorously defend the authority to invest in their own transmission systems and earn steady, FERC-authorized rates of return on this capital investment. While the U.S. needs more transmission, FERC has not pointed to any empirical evidence suggesting that its existing incentive policies are an obstacle to new investment.
In those situations where an incentive is actually needed to help promote investment in a beneficial transmission project, FERC's current incentive rules are more than adequate. The existing regulations focus on addressing a proposed transmission project's risks and challenges by allowing the use of risk-reducing rate mechanisms. A utility, for example, might be granted the right to recover 100 percent of project development costs if a transmission project is canceled for reasons beyond the utility's control. This emphasis on risk-reducing incentives makes sense. By addressing obstacles to the development of transmission projects (such as the risk of having to write off sunk development costs if a project must be abandoned), FERC's rules encourage transmission investment. Where risk-reducing incentives have been pursued but are insufficient to mitigate project risks, FERC will consider awarding revenue-enhancing incentives, particularly basis point "adders" that increase the authorized return on equity (ROE) for a transmission project, and, the theory goes, make it easier to attract capital investment in the project.
Utilities must justify the total package of requested incentives in light of the project's risks and challenges. This requirement to show a "nexus" between the requested incentives and project development needs helps ensure that FERC's incentive rules comply with the bedrock ratemaking principle that incentives should not be awarded in situations where they are not actually needed to encourage investment.
FERC's existing emphasis on risk-reducing incentives that address specific obstacles to beneficial development is workable and strikes an appropriate balance between consumer and investor interests.
The Challenges of Benefits-Based Incentives
The pending changes to FERC's incentive rules would upend the existing framework by focusing only on whether a project is beneficial. Proof that a project will benefit consumers certainly should be a prerequisite for receiving incentives, but project benefits cannot be the only criterion. Utilities should also be required to demonstrate that an incentive actually influences the decision to invest in the transmission project, or, as FERC Commissioner Richard Glick put it, "incentives must actually incentivize something."
A test that focuses only on a project's benefits runs the risk of providing utilities a handout for projects that would be built anyway, contrary to longstanding court precedent recognizing that rate incentives should only be awarded when needed. FERC's proposed rules, for example, would award lucrative ROE adders to projects that meet certain economic cost-benefit ratios, without any showing that incentives play a role in the decision to invest in the project. Utilities shouldn't need incentives to invest in projects that provide clear economic benefits. It is exactly these types of projects, in fact, that should be identified through the regional planning processes that FERC has promoted through its landmark Order Nos. 890 and 1000. These incentives would simply provide a windfall to utilities for projects that a properly functioning planning process should already be identifying and getting built.
An exclusive focus on project benefits in awarding incentives also raises difficult questions about how to measure the benefits to determine whether a project is worthy of incentives. The problem is particularly acute when it comes to incentives aimed at improving reliability. FERC has acknowledged that reliability benefits can be even more difficult to quantify than economic benefits (which are subject to no little controversy themselves). The Commission's proposed incentive rules nonetheless offer ROE adders for projects that provide reliability benefits above and beyond mandatory reliability standards. But the proposal is sorely lacking in metrics to use to identify or quantify the alleged merits of projects seeking incentives based on reliability benefits. Projects that provide more than an adequate level of reliability are not necessarily beneficial or cost-effective for consumers, and the lack of clear standards in FERC's proposal would make it difficult to separate truly beneficial projects from those that fail to provide meaningful value to customers.
Better Planning, Not Incentives
FERC has tried to justify its incentive reform by asserting that an evolving electric industry requires new types of transmission. It is hard to argue with the assessment that the grid could benefit from new types of transmission projects. FERC's proposed incentive rules, however, are unlikely to encourage transmission projects that differ from those spawned by current planning processes. As Commissioner Glick observed, FERC's new incentives would largely target "low-hanging fruit" projects that are already identified in regional transmission planning processes.
A need for new types of transmission does not mean that FERC needs a new incentive policy. On the contrary, if the most needed types of transmission projects with the greatest benefits aren't being planned and built under regional transmission planning processes, incentives are unlikely to be an effective solution to the problem. Stubborn obstacles such as state siting challenges, disputes over cost allocation, and shortcomings in the planning process itself are primarily to blame for shortfall in certain types of needed transmission, such as large interregional projects. A recent report prepared by FERC staff highlighted just these kinds of challenges as impediments to the development of high voltage transmission projects. The report did not include a lack of adequate incentives in the barriers it identified to such projects.
The impact of planning process limitations on beneficial transmission development is evident in the growth of transmission projects in Regional Transmission Organization (RTO) and Independent System Operator (ISO) regions that do not go through the full regional planning process conducted by the RTO/ISO. In PJM Interconnection, for example, investment in so-called "supplemental projects" that are planned by individual transmission owners has significantly outstripped spending on "baseline" projects subject to the full PJM planning process. Supplemental project costs in 2019, for example, were $3.4 billion, compared to $1.5 billion in baseline projects.
Transmission projects that are not reviewed in the full RTO/ISO planning process may not be the most cost-effective solution to a transmission need. Commissioner Glick has cogently observed that the proliferation of projects that bypass the full Order No. 1000 regional planning process is likely attributable in part to the fact that these projects are not open to competition under Order No. 1000, and transmission owners thus have an incentive to focus on smaller, local projects that may not provide the most value to customers. Addressing this concern would involve revisiting FERC's transmission planning policies, not rewriting the incentive rules.
FERC should take steps to evaluate the status of competitive transmission development under Order No. 1000, including an assessment of the potential for increased transmission competition to temper transmission cost increases in some or all planning regions.
If FERC moves forward with its proposal to revise its transmission incentive regulations, it should restrict project-specific transmission incentives to projects evaluated and approved in a full regional transmission planning process under Order No. 1000. Such a condition would reinforce participation in regional planning, help ensure that all projects seeking incentives in a particular region are analyzed using consistent criteria and standards, and provide greater assurance that projects receiving incentives will actually deliver consumer benefits.
In addition, an entity seeking an incentive for a particular project should be required to demonstrate that there is at least a rational relationship between each incentive sought and the decision to invest in the transmission project. This would provide some assurance that the incentive will "actually incentivize something," in accordance with longstanding incentive rate requirements.
Promoting Joint Ownership
A feature of FERC's existing transmission incentive policy that is omitted altogether from FERC's proposed rewrite is the effort to promote joint ownership of transmission facilities, particularly joint ownership opportunities for public power and cooperative utilities. FERC has consistently recognized the benefits of joint ownership of transmission facilities, finding that such arrangements can diversify financial risk across multiple owners and minimize transmission siting risks. FERC said in its Order No. 679-A that it would "look favorably on an incentive request that includes public power joint ownership," and the Commission's current incentive policy encourages joint ownership by making it easier for utilities requesting ROE incentives to make the case that they have taken steps to reduce project risk through joint ownership.
If the Commission proceeds with the proposed rules, it should remedy this omission and make room in its incentive policy to promote joint ownership by public power and cooperative utilities. At a minimum, any project for which joint ownership arrangements may have been feasible but were not pursued should face heightened scrutiny in seeking incentives.
A Windfall for RTO and ISO Members
Perhaps the most problematic aspect of FERC's revised incentive rules is the proposal to double the ROE incentive adder for participation in RTOs and ISOs (from 50 to 100 basis points), and to make the incentive available regardless of the voluntariness of RTO/ISO participation. Unlike the project-specific adders discussed above, the RTO/ISO participation adder applies to all of a utility's transmission facilities. Section 219 of the FPA requires FERC to provide incentives for each utility that "joins" an RTO or ISO, but there is nothing in the statute that says the incentive must take the form of an ROE adder, or that the incentive must apply for the entire duration of a utility's RTO/ISO membership. FERC's proposal to literally double down on an already overly generous RTO/ISO participation adder would provide utilities with an unjustified windfall that will increase transmission costs without providing any corresponding increase in benefits for customers.
FERC does not point to any evidence that the proposed increase to the adder is necessary to encourage new, let alone continued, RTO/ISO participation. And awarding the adder to utilities whose RTO/ISO participation is not voluntary (because it is required by state law or other legal mandate) runs afoul of the bedrock principle that incentives should not be awarded for actions that a utility is already required to undertake.
Rather than doubling the RTO/ISO participation adder, FERC should revise its rules to provide that a utility's adder will phase down over time to reflect the distinction between an incentive to encourage joining an RTO/ISO and one for voluntarily remaining an RTO/ISO member. For example, the adder might remain in place at the initial level for a four-year period following the effective date of the public utility's membership start date, and then phase out over a subsequent two-year period.
FERC should also restrict eligibility for the RTO/ISO participation adder to projects approved through the RTO/ISO regional transmission planning process - one of the key intended benefits of RTO/ISOs. To promote regional planning, non-regionally planned projects should be ineligible for the RTO/ISO participation adder.
What FERC Should Do Next
FERC should reconsider its proposal to rewrite its current transmission incentive rules. If the Commission wants to promote beneficial transmission projects that respond to evolving industry needs, its attention would be better focused on removing obstacles to new investment presented by the transmission planning process and disputes over cost allocation. If FERC proceeds with the revised rules, it should adopt changes to the proposal that would ensure that incentives actually encourage transmission investment that provides value for consumers.
John McCaffrey is senior regulatory counsel at the American Public Power Association. Throughout his career with APPA and in private practice, he has advocated before FERC, state public utility commissions, and federal and state courts on a variety of energy regulatory issues. He holds a B.A. in Political Science from Boston College and his J.D. degree from the George Washington University Law School.