Cost allocation should be addressed only after all of the potential benefits of a project have been assessed, according to a study commissioned by WIRES and released on July 23.
“Addressing cost allocation too early in the planning process or strictly on a project-by-project basis can create strong incentives for some market participants and policy makers to understate benefits during the planning and project evaluation process in an effort to reduce their cost responsibility for a project,” according to the study performed by consulting firm The Brattle Group. “This can result in the rejection of even very valuable projects.”
The Brattle Group conducted a three-fold study to document the broad range of transmission benefits and how they can be identified and estimated for specific transmission investments; discuss the experiences of RTOs and non-RTOs in analyzing the economic, public policy and other benefits that new or upgraded transmission can provide; and catalogue the range of potential benefits offered by transmission investments, and summarize the experience with the estimation of these benefits.
The study comes as conversations continue in the industry on how to meet FERC Order 1000’s cost allocation requirements and as FERC issues decisions on regional cost allocation proposals.
Transmission projects traditionally have been proposed and developed by vertically integrated utilities that need to maintain reliability on their transmission systems, but that model is quickly becoming insufficient to address the benefits that other types of projects, such as economic and public policy projects, may provide. The method that is used today to model benefits relies on simplified cost production analyses, which fail to help transmission planners adequately assess transmission needed, the firm said.
“While production cost savings are readily estimated (based on simplified assumptions), the results only provide estimates of the short-term dispatch-cost savings of system operations,” the firm said. “These savings are only a portion of the overall economic benefits provided by transmission investments and do not capture a wide range of other transmission-related benefits, including many long-term capital and operational cost savings.”
The Brattle Group developed a checklist of benefits to be used during conceptualization efforts to help planners identify potentially beneficial projects and their associated benefits. The firm also made a series of recommendations when considering benefits, including that neighboring regions evaluate interregional projects according to the full set of benefits that regions consider when evaluating benefits; that both near- and long-term uncertainties be evaluated; and that benefits be compared with estimated project costs, either on a present value or levelized annual basis, over a time period that reflects the useful life of the assets, such as 40 to 50 years.
“This approach is particularly important because many benefits tend to increase over time with both load growth and fuel price inflation and because the regulated revenue requirements are ‘front-loaded’ and tend to decrease over time as the facilities are depreciated,” the firm said.
The consulting firm also recommended that cost-benefit analyses consider benefits that accrue not just to a single utility’s system or a single planning region but to market participants and the economy as a whole.
“Recent transmission planning experiences have … shown that the scope of transmission-related benefits generally extends beyond the main driver of a particular project,” the firm said.
For example, a reliability-driven project may also reduce congestion and support the integration of renewable generation, while a transmission project driven by economics may also increase system reliability, avoid or delay having to build reliability projects, or reduce system-wide investment needs by allowing access to lower-cost generation.
“This multi-purpose, multi-value aspect of transmission investments requires a more systematic analysis of the wide range of transmission-related benefits and the interaction of transmission investments with other system-wide costs and non-transmission investments,” the firm said.
Taking this one step further, The Brattle Group noted the indirect benefits of a line. For example, a transmission project could offset the need for generation that produces harmful emissions; reduce the cost of meeting public policy goals; defer generation investment needs in resource-constrained areas; reduce the need to cycle fossil-fuel power plants; and reduce the impact of extreme weather events.
Framework to identify benefits
The Brattle Group proposed using a four-step framework to help identify all of the benefits a proposed project may provide.
The first step is to bring together system planners, project developers and stakeholders to identify potential transmission projects that could supplement or replace baseline reliability projects and to develop a comprehensive list of their likely benefits. During this step, only two questions should be asked: what transmission projects would likely be beneficial in addition to or instead of those that have been identified to meet reliability standards, and what are the likely benefits that these projects would offer and why are they significant?
The consulting firm said that this step would be most effective when facilitated by independent, unbiased planning professionals, such as RTO staff. The second step is to perform an unbiased evaluation of the proposed projects from both a reliability and economic perspective and to estimate the value of as many of the potential benefits without regard to how the benefits would be allocated across a region, to neighboring regions, or to different groups of transmission customers, generators or other market participants. To do this, benefits can be assessed through adjusted production cost metrics, or, for projects whose benefits may be significant but difficult to assess, through estimating at least their likely range and magnitudes, “rather than implicitly assuming that they have zero value because their precise values are difficult to calculate,” the Brattle Group said. The third step is to determine whether the proposed transmission investments would be beneficial overall by comparing the magnitude of economy-wide benefits with estimated project costs. “Once the overall value of benefits has been estimated, a benefit/cost ratio can be calculated and compared to the applicable threshold to determine whether a project or portfolio of projects is worth pursuing,” the firm said. During this step, non-transmission alternatives, such as energy efficiency initiatives, should be considered. The fourth and final step is to address cost allocation. “Aggregating beneficial transmission projects into larger portfolios of projects can simplify the necessary cost allocation analyses, reduce misperceptions that benefits appear to accrue only to a limited subset of market participants, and thus facilitate cost allocation,” the firm said. To calculate the present value of costs and benefits, or the “levelized” annual value of these benefits and costs, requires the selection of a discount rate, the firm said. “We recommend using the weighted-average cost of capital (WACC) or the allowed rate of return of the transmission owner as the discount rate for this purpose,” the firm said. “Others have also evaluated projects using a much lower social discount rate. For example, [the Midcontinent ISO] uses in its evaluation of [multivalue projects] both a 20- and 40-year [net present value] with two discount rates: 3% (to reflect a ‘societal’ rate) and 8.2% (to reflect the allowed rates of return of transmission owners).” The Brattle Group suggested several approaches to allocate costs in a manner that is commensurate with benefits, noting that cost allocations based on non-monetary metrics can be more practical as long as it can be shown that these metrics result in cost allocations that are roughly commensurate with the allocation of overall economic benefits. “For example, costs could be allocated to beneficiaries based on each entity’s relative contribution to the need for a project—as long as such relative contributions to need are roughly proportionate to the benefits received by each entity,” the firm said. “Costs could also be allocated based on each entity’s projected or allocated usage share of the projects’ added transmission capability (e.g., allocated shares of increased flow-gate capacity).” The firm continued, “Other examples of cost allocations include applying load-ratio shares or shares of power flows that drive reliability-based upgrades, apportioning costs based on the power purchases of various load-serving entities when allocating the costs of renewables-integration driven projects, or using the project’s physical location in each entity’s footprint (e.g., shares of circuit miles or direct assignment of project segments) if there is agreement that such usage or footprint-based shares are roughly proportionate to the benefits received by each party.” The Brattle Group noted that the nature and magnitude of benefits can change significantly over the course of an asset’s operational life. “For example, benefits associated with today’s transmission grid, such as the ability to operate competitive wholesale electricity markets, could hardly have been imagined or estimated when the facilities were built four or five decades ago, long before the advent of open access to the transmission grid,” the firm said.