The U.S. has been investing between $20 billion and $25 billion annually in improving the nation’s transmission grid. Over 90 percent of these investments are justified based on: (1) the local reliability criteria of transmission owners, including the replacement of the many aging transmission facilities built before the 1970s; (2) the local and regional reliability upgrades triggered by generation interconnection requests, which are now dominated by renewable generation and storage resources in many regions; and (3) the reliability criteria associated with regional planning processes conducted by independent system operators (ISOs) and regional transmission operators (RTOs). To date, only a small portion of transmission spending is justified on economic criteria and full analysis of broader regional and interregional benefits and costs.
As we have pointed out in prior work (summarized here), this disproportionate focus on specific transmission reliability needs results in piecemeal upgrades that do not offer the highest-value, lowest-total-costs solutions to modernize our electricity grid. For example, the current approach may not identify opportunities to “up-size” reliability projects to capture additional benefits, such as congestion relief and reduced transmission losses. Neither does it identify investments that create options and increased grid flexibility to respond to uncertain market and system conditions. Similarly, the in-kind replacement of aging existing facilities does not take advantage of opportunities to better utilize scarce rights-of-way for upsized projects that can meet multiple other needs and provide additional benefits, such as addressing reliability needs, relieving market congestion, and integrating more renewable generation. And the current piecemeal approach certainly does not yield any larger regional or interregional solutions, such as transmission overlays, that could more cost-effectively address the nation’s public policy needs.
Improving Planning Processes
Improving transmission planning, generation interconnection, and cost allocation processes is the subject of the Federal Energy Regulatory Commission’s (FERC’s) much-anticipated Advance Notice of Proposed Rulemaking (ANOPR), with stakeholder comments due on October 12, 2021. This effort will require improving every phase of the planning processes, as illustrated in the figure below. Improvements will have to center around (1) expanding initial needs assessment and project identification, (2) improving benefits analyses to determine the transmission solutions that are most effective from a total system-wide cost perspective—which, in the case of reliability projects, currently consists only of showing that the proposed project is a least-cost solution for the identified reliability need; (3) refining project cost recovery (i.e., cost allocation) to be commensurate with benefits; and (4) presenting the needs, benefits, and proposed cost recovery to obtain approvals from the various federal and state permitting and regulatory agencies.
TRANSMISSION PLANNING PROCESS
To demonstrate a clear need for transmission projects, the planning processes can be improved by taking advantage of the last decade’s industry experience. As reflected in the discussion and summary table below, this experience shows that effective planning processes are more proactive, explicitly address long-term uncertainties, and employ a multi-value planning paradigm. More specifically, to increase their effectiveness, transmission planning processes will need to:
1. Broaden the determination of transmission needs and solutions. Regional, interregional, and national planning pathways are needed that proactively go beyond the prevalent approach of narrowly addressing mostly local and regional reliability needs. This may include the specification of interregional reliability needs, the creation of a national planning authority or joint planning by neighboring regions that can address both state and national public policy needs, and the improved regional planning that simultaneously considers the multiple needs at the local, regional, and interregional levels.
2. Approach every transmission project as a multi-value project. Investments in transmission infrastructure can proactively address multiple long-term needs and provide a wide range of long-term benefits. Explicitly recognizing this value is particularly important for justifying the cost of grid investments that address multiple needs and for interregional transmission projects, since a project may address reliability needs in one region but public policy needs in the other.
3. Evaluate individual projects (or synergistic portfolios of projects) based on a broad range of transmission-related benefits. Well-planned transmission infrastructure investments (including grid-enhancing technologies) offer economic, public policy, reliability, and avoided-cost-related benefits that reduce overall system-wide costs. Planners can take advantage of the already-extensive industry-wide experience with quantifying these benefits, as shown in the summary table below.
4. Address short- and long-term uncertainties explicitly and proactively. Long-term uncertainty can be addressed by evaluating projects for scenarios that represent a broad range of plausible futures. Short-term uncertainties (such as extreme weather events, which can occur in any of the futures) can be addressed through sensitivities. “Least regrets” planning tools can then be employed to reduce the risk that some future outcomes may lead to either (a) the regret that the cost of building the project significantly exceeds the project’s benefits, or (b) the regret that not building the project results in very-high-cost outcomes that far exceed the project’s cost. Reducing the cost of both types of regrettable outcomes is necessary to reduce the project’s overall risk in light of an uncertain future.
5. Determine cost allocation based on the broad range of transmission-related benefits and for entire portfolios of projects. Such an approach to cost allocation takes advantage of more stable and widespread benefits of a larger portfolio of projects and recognizes multiple transmission-related values. Using portfolio-based cost allocations (as opposed to project-specific cost allocations) will be significantly less contentious and more in line with the cost recovery approaches used for most other infrastructure.
The Planning Imperative
It will be critical to supplement or modify the existing processes for transmission planning and generation interconnection with approaches that employ the above five principles—such as New York’s recently implemented multi-value planning process for public policy transmission needs (summarized in the right-hand column of the table below). Without improved planning, we will not be able to build the more cost-effective, more flexible electricity grid necessary to meet reliability, economic, and public policy needs at lower overall costs. In fact, without improved planning processes we may not even be able to bring online the clean-energy resources necessary to achieve the public policy mandates in place today.
EXISTING EXPERIENCE WITH MULTI-VALUE ANALYSES OF TRANSMISSION BENEFITS
Source: Transmission Planning and Benefit-Cost Analyses, The Brattle Group, April 29, 2021, page 9.
Johannes P. Pfeifenberger
Principal
The Brattle Group
Johannes,
As usual, your piece is SPOT ON! The statement “As we have pointed out in prior work, this disproportionate focus on specific transmission reliability needs results in piecemeal upgrades that do not offer the highest-value, lowest-total-costs solutions to modernize our electricity grid” really rings true. We need to look broader across the regions and more holistically. Thank you!
Nice article…thanks. As with any piece about transmission and generation planning I feel the need to make sure everyone understands…our system is becoming weather driven! That doesn’t mean a cold wave will result in some short lived infrastructure challenges like it does today. It means that the combination of a large scale event that combines weather variables that drive load up and RE resources down for several days or weeks may result in an emergency that will stop the energy transition in its tracks. The current situation in Europe is a preview to how that could look by 2025. It doesn’t matter how much offshore wind you build, if it’s all under the same weather regime we’ll still be short. But it doesn’t need to be this way. Our sector needs to understand that long term storage solutions are off on the horizon, and our focus needs to be on building a robust system where generation and transmission are planned around weather such that transmission is designed to tap weather variability at scales that matter, and generation is incentivized where it will provide the energy that is needed AND the capacity WHEN needed, versus maximum PTC value. Future “Extreme weather” from the grid perspective will likely be fairly boring relative to our current perspective. We need the tools, datasets and effort to plan effectively at the required scales. My 2C FWIW.
Great article! Appreciate the portfolio view perspective and organized market/RTO comparison. Working for an IOU in the pacific northwest presents additional challenges where utilities and non jurisdictional entities need to work together to plan our long term transmission and generation interconnections now and looking out 20+ years.