Clarifying Electric Transmission Benefits
Resurgent electricity demand and turnover in the generation fleet are creating the need for substantial transmission expansion—perhaps twofold or more in coming decades. The prospects for expansion have consumer groups alarmed because existing policies result in costly, inefficient transmission development. As research and customer groups attest, transmission policy needs an overhaul to ensure expansion of the grid maximizes net benefits.
Transmission planning and development operate somewhat differently at the local, regional and interregional levels, with each level presenting different opportunities for reform. A complaint filed by the Office of the Ohio Consumers’ Counsel before the Federal Energy Regulatory Commission (FERC) documents over six billion dollars spent by Ohio utilities on local transmission projects without any cost-benefit or cost-effectiveness analysis. The complaint highlights the “regulatory gap” between state and federal regulators in which utilities spend at captive consumer expense with no competition and little corrective oversight. Excessive spending on local transmission projects can undermine the value of more efficient regional transmission projects.
Regional transmission investment usually proceeds with reliability and market-efficiency projects considered in separate silos: Reliability projects are evaluated without looking at potential economic benefits, while market-efficiency projects are evaluated without considering reliability benefits. Evaluations that neglect potentially significant benefits are unlikely to best serve either reliability or market efficiency. Presently, more than 90 percent of the $20-$25 billion spent annually on transmission is channeled into monopoly utility projects built without competitive bidding or thorough economic justification.
Meanwhile, current policy impedes the development of interregional transmission estimated to save consumers billions of dollars annually, in part because neighboring regions define benefits differently. Interregional merchant high-voltage direct current transmission projects—financed by private investors instead of regulated monopolies—say their projects are undervalued by regional transmission organizations (RTOs) because regional grid operators fail to credit the benefits their projects offer.
A common thread across interregional, regional and local scales is that stakeholders struggle to agree on how to define, measure and apply transmission benefits in regulatory processes. And while local, regional and interregional projects are generally considered in separate stakeholder processes, they often have direct consequences for projects at other levels. Clarity on benefits is essential to ensuring the most valuable projects move forward.
Pinning Down Transmission Benefits
Disagreements over transmission benefits are at the core of the FERC-stalled proposed rules on regional transmission planning. FERC’s proposal identifies 12 benefit categories, seeking input on the descriptions, how they should be identified and whether transmission providers should be required to consider each of the benefits. Hundreds of comments have been filed in the rulemaking process, exhibiting both the complexity of transmission planning and the desire of incumbent transmission providers to maintain or expand their privileged positions. Transmission planning is also closely linked to generator interconnection processes. A recent FERC order made some progress on interconnection queue reform but, as anticipated, the rule did not go far enough.
The Commission’s proposed list of transmission benefits and descriptions are shown in Table 1.
Table 1: Long-Term Regional Transmission Benefits
Source: Federal Register
In R Street’s comments on the Notice of Proposed Rulemaking (NOPR), we urged the Commission to require cost-benefit evaluation of proposed transmission expansion for projects at every level, with such evaluation including consideration of a minimum set of well-defined benefits. Not only would such a requirement improve regional planning quality, it would also facilitate comparison of local and regional projects and make it easier for neighboring transmission providers to engage in interregional planning. Assessing merchant transmission projects on this same framework would reduce the barriers currently delaying such efforts. Critical to the success of this approach is how well the Commission implements the requirement. Merely suggesting a list of benefits for transmission providers to consider risks perpetuating the status quo.
The NOPR’s proposed list of benefits is generally sound. It neglects potential insurance and risk mitigation benefits; however, these may overlap with benefits already listed and result in double-counting. Some benefit categories may be small—and thus irrelevant when choosing among alternatives—but the Commission should ensure that system-wide benefits like increased competition or increased market liquidity are considered. Transmission providers may pursue projects to meet state policy goals. The costs of any public policy project failing a cost-benefit test should be allocated to the entities requesting the project.
One critical improvement to the proposal is in the measurement of the reduced loss of load probability, which should be redefined as the avoided value of lost load to ensure compatibility with economic assessments. This redefinition would enable consistency across various aspects of cost-benefit analysis and could form the basis for a consolidated cost-benefit framework. Reliability is an economic concept, even if generally phrased in engineering terms, and the integration of reliability and economic evaluation of projects is essential to improve transmission planning.
Next Steps
Identifying the effects of transmission development is inherently difficult in a networked grid. In addition to the grid’s intrinsic complexity, pathways toward economic development and public policy are unclear. Recognizing these uncertainties, transmission providers should employ a robust program of scenario and sensitivity analysis to inform project selection.
RTOs have had success developing transmission in a multi-value framework, but use of such approaches remains rare. Transmission providers should assess every transmission project as a multi-value project; otherwise, analyses will be biased, planning will be fragmented and transmission spending will be wasted. Establishing a minimum set of transmission benefits for evaluation should produce more customer-oriented, cost-effective transmission development at the local, regional and interregional levels. Revising reliability metrics into a form compatible with economic benefits would enable further improvements in transmission planning.
The proceedings mentioned earlier give FERC the opportunity to define minimum transmission benefits. This involves regional stakeholders actively working to categorize and measure these benefits in ways that align with neighboring regions. It is crucial for regions to focus internally on aligning transmission benefits with local transmission and state-regulated cost-of-service generation oversight. By doing so, they can ensure the identification of least-cost transmission solutions. These solutions often start at larger scales to leverage economies of scale, effectively displacing less-efficient investments like excessive local transmission builds or new generation projects that cost more than importing affordable power from other parts of the power system. Substantial evidence indicates that such an approach could save consumers billions of dollars while enhancing grid reliability.