Published: March 16, 2023

By: Danielle Powers, Executive Vice President

The Massachusetts Department of Energy Resources (“MA DOER”) issued the framework for its proposed Forward Clean Energy Market (“FCEM”) in January of 2023, and invited written comments on the proposal. Comments were submitted by numerous interested parties, including market participants, utility ratepayers, advocacy groups, and concerned citizens. A review of the submitted comments revealed some common themes.

One of the most consistently submitted comments was the desire for a robust stakeholder process. Many parties requested that the MA DOER work with other New England states to establish a formal public stakeholder process to consider, discuss and debate the FCEM proposal via technical conferences and public comment periods. The parties reasoned that this would allow the involvement of stakeholders not directly involved in the energy markets (e.g., ratepayers, community groups, and environmental advocates) and give a voice to those ineligible to participate in meetings involving the design and operation of the New England energy markets. An open and transparent stakeholder process is critical in moving a proposal forward and designing a market with the greatest chance of success.

In addition, several parties recognized that the proposed market design is highly complex. This complexity can potentially restrict competition by developers and clean-energy resource suppliers, and substantially limit the possible benefits of the proposed market. In addition, it will take years to resolve questions and details around jurisdiction, governance structure, interaction with existing wholesale markets, multiple products and multiple commitment periods, and the auction mechanism.

The existing capacity market took dozens of meetings among over 80 stakeholders for almost two years to finalize and implement, and the proposed FCEM is far more complex than the current market. It is reasonable to assume that this market would not be implemented until 2025 for a 2028 delivery period at best. This delay is a critical issue in achieving the objectives of the FCEM.

The comments submitted also recognized the importance of alignment between the FCEM and the existing regional wholesale markets. For the FCEM to successfully meet region-wide policy goals and reliability needs, the market must be compatible with the existing wholesale markets administered by ISO New England. While this does not require FCEM and current wholesale market integration, the need to consider the obligations, requirements, and revenues associated with the FCEM in the existing wholesale markets is unavoidable.

Finally, several comments on the proposed FCEM centered around the failure of the existing capacity market in New England in advancing the state’s climate mandates and integrating these mandates into the competitive markets. This criticism is unfounded. The competitive energy markets are designed to provide reliable wholesale electricity at competitive prices, not to address public policy mandates.

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All views expressed in this summary are solely the current views of the Author and do not necessarily reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, and related companies, and the clients of Concentric Energy Advisors. The Author’s views are based upon information the Author considers reliable at the time of publication.

Published March 14, 2023

By Concentric Staff Writer

Federal energy and environmental regulators agreed to a framework to collaborate on electric reliability as the U.S. grid transitions to zero-emission resources and warnings come of possible problems in the future.

The March 9 memorandum between the Department of Energy and the Environmental Protection Agency describes the “roles and responsibilities” of each agency with regard to reliability, which has become more of a question as electric generation resources are retired and replaced with renewables, energy storage, energy efficiency, and demand response.

The memorandum “also outlines activities that our agencies will undertake individually and collectively to monitor, share information and consult to support the continued reliability of the electric system,” the document states.

Noted in the memorandum is that each plays a role in the creation of policy and disbursal of funds for the power sector and that both have expertise in the role of maintaining electric grid reliability. The framework will be revised and amended “as necessary.”

The Federal Energy Regulatory Commission, which regulates wholesale energy markets and the interstate transmission of electricity, natural gas, and oil, will also engage with the EPA and DOE on reliability, the memorandum states.

The document states that the U.S. electric grid has undergone a rapid transition to low- and zero-emission energy resources, energy efficiency, and demand response concurrent with a rise in extreme weather events, including heat waves, droughts, and intense cold that have caused electricity outages. In August 2020, heat wave-related rolling outages struck California, and in February 2021, severe cold crippled electric-grid infrastructure in Texas, leading to hundreds of deaths.

The memorandum comes after the PJM Interconnection in February issued an analysis saying that reserve margins are declining in its 13-state region for the first time due to 40 GW of generation retirements, including 25 GW of policy-driven retirements, as demand grows. Also, the North American Electric Reliability Corp. in its December 2022 Long-Term Reliability Assessment identified the California/New Mexico region, the Midcontinent Independent System Operator, and Ontario, Canada as regions or areas as “high risk,” where anticipated reserves will fall below margins considered necessary to meet reliability thresholds.

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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Published: February 16, 2023

By Concentric Staff Writer

Development of large-scale nuclear energy facilities has stalled in the U.S., but a new technology—small modular reactors—is a promising new frontier. Commercializing a nascent and ground-breaking method of power production is never simple, however, as developers are finding.

In the years following the accident at the Three-Mile Island nuclear power plant in Pennsylvania in 1979, and other events such as the Chornobyl accident in 1986 and the Fukushima accident in 2011, the development of large new nuclear power plants in the U.S. has fizzled. There are currently only two large reactors under construction nationwide: Units 3 and 4 at the Vogtle Electric Generating Plant in Georgia. This expansion began in 2009 and has been plagued by delays and cost overruns, with its initial $14 billion estimated cost ballooning to $28.5 billion by last year. The situation illustrates the difficulties in developing new utility-scale nuclear power. As of May 2022, 54 nuclear power plants were operating in the U.S., comprised of 92 individual reactors, according to the U.S. Energy Information Administration.

However, small modular reactors (“SMRs”) are enjoying a push in investment and development. One leading developer, Portland, Oregon-based NuScale Power (“NuScale”), on Jan. 1 submitted its standard design application for its SMR to the U.S. Nuclear Regulatory Commission (“NRC”). NuScale’s Carbon Free Power Project (“CFPP”) would be the first facility of its kind and is due to begin generating power in 2029 and be fully operational by 2030. The 462-MW SMR would be at the site of the Idaho National Laboratory near Idaho Falls and would sell power into the regional Western Energy Imbalance Market operated by the California Independent System Operator.

The standard design certification is one of three that NuScale will require from the NRC. In July, the NRC directed its staff to certify that a safety application submitted by NuScale in December 2016 meets the agency’s safety standards. Next year, NuScale and Utah Associated Municipal Power Systems (“UAMPS”), the offtaker for NuScale’s planned SMR at the Idaho National Laboratory, will submit a combined license application to the NRC.

The NRC responded to NuScale’s draft application, which sought to identify any missing information or any technical or regulatory details that might complicate the application’s acceptance or regulatory review. In a Nov. 15 letter, NRC said it identified several challenging or significant issues regarding the application, including details about power system safety classifications, assessment plans for vibration assessment and steam generator tube support, and other technical details regarding containment vessel and reactor material and potential accidents.

Despite heavy federal support and investment, only about one-third of the CFPP’s planned capacity has been contracted to UAMPS members, leaving about two-thirds of its output unaccounted for. It will need more commitments for its output to be economically viable.

NuScale, like other power generation concerns, is also facing steeply increasing costs. In 2016 the company estimated costs from the CFPP would be about $55 per MWh, but that amount has steadily increased and company representatives have recently said publicly that the projected cost could be as high as $100 per MWh. In the past two years, the company has experienced sharp rises in the costs of steel, electrical equipment, copper wire, and cable, as well as other commodities necessary for construction of the plant, it said in a Jan. 9 press release discussing an updated project cost estimate.

“The Department has long recognized the transformational value that advanced SMRs can provide to the nation’s economic, energy security, and environmental outlook,” DOE said in an SMR fact sheet. “Accordingly, the Department has provided substantial support to the development of light water-cooled SMRs, which are under licensing review by the NRC and will likely be deployed in the late 2020s to early 2030s.”

DOE initiated an Advanced SMR R&D Program in fiscal year 2019 to support research, development, and deployment activities in the U.S. and foreign markets. DOE in an online posting acknowledged that “significant technology development and licensing risks remain in bringing advanced SMR designs to market,” requiring government support. In 2017, the Department issued a multi-year, cost-shared funding opportunity (U.S. Industry Opportunities for Advanced Nuclear Technology Development, DE-FOA-0001817), which it has awarded to various advanced nuclear technologies.

SMRs generally have a capacity of up to 300 MW per unit, which is about one-third the capacity of traditional nuclear power plants, according to the International Atomic Energy Agency (“IAEA”). Prefabricated units can be built, shipped, and installed onsite, unlike regular plants that often have to be custom designed for the intended site. There is also a subset of SMRs called “microreactors” that can be built up to 10 MW equivalent and have smaller footprints than regular SMRs. SMRs also require less frequent refueling, typically every three to seven years, compared with one to two years for conventional plants. Some SMRs can operate for up to 30 years without refueling, according to the IAEA.

The world’s first floating nuclear reactor, Russia’s small-capacity Akademik Lomonosov, began commercial operation in May 2020 and other SMRs are under construction or undergoing licensing in Argentina, Canada, China, Russia, and South Korea. There are more than 70 commercial SMR designs being developed around the world, the agency said.

NuScale is also working with several partners, including Shell Global Solutions, to develop an integrated energy system to produce hydrogen from electricity and process heat from NuScale SMRs. NuScale says its SMR technology holds the potential to balance and stabilize power grids dominated by renewables through hydrogen production. Hydrogen would be used as an end product or as a stored energy resource.

Although a leader in the field, NuScale is not the only developer of SMRs—there are dozens of companies around the world developing SMR proposals, many of them in the conceptual design stage. If SMRs can gain acceptance from the American public and avoid the concerns of their large-scale predecessors, SMRs might become a more familiar aspect of the power production landscape.

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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Published: June 10, 2022

By: Concentric Staff Writer

Federal energy regulators are pushing forward with reforming rules around planning and siting new transmission lines needed to bring planned renewable resources online. Still, as with previous efforts, there are questions about how effective the initiative will be.

The Federal Energy Regulatory Commission’s (FERC) draft notice of proposed rulemaking on transmission planning and cost allocation (NOPR), issued on April 21, is garnering much attention across the industry. Stakeholders, including electric utilities, regional transmission organizations, state public utility commissions, and environmental groups realize that new transmission facilities are needed to maintain system reliability and deliver large amounts of new renewable generation to load centers. But scrutiny around the proposed rules is intense, with questions as to whether or not they will lead to new transmission build-out and how the initiative will meet the needs of states, transmission developers, and ultimately, electricity consumers.

The NOPR is intended to build upon and correct perceived deficiencies in its Order No. 1000, issued in July 2011 and affirmed in Order No. 1000-A in May 2012. Order No. 1000 (Order 1000) has been the primary federal directive regarding transmission planning and cost allocation, but there has been broad recognition that construction of new facilities in recent years has not kept up with the grid’s needs. The new federal rulemaking is intended to address long-running roadblocks and procedural issues surrounding new transmission, and the stakes are high for consumers and investors as the U.S. navigates the transition to cleaner electricity.

FERC Chairman Richard Glick laid out the goals of the rulemaking in a statement that coincided with the release of the NOPR.

“Transmission facilities provide a broad range of benefits,” Glick said. “Planning for those facilities with a longer-term forward-looking approach, in addition to fairly allocating their costs, is essential to ensuring we are developing energy infrastructure in a manner that reduces costs and enhances reliability.”

Transmission siting in the U.S. has gotten trickier in recent decades. New facilities are often opposed by local residents who do not favor large rights-of-way, and transmission infrastructure cutting through forests, plains or desert areas. Localities will also periodically oppose related projects connected to the transmission expansion, such as substation improvements.

In the area of new transmission planning, the NOPR would require public utility transmission providers to conduct long-term regional planning to meet the changing generation and energy storage resource mix and rising electricity demand that is occurring in many places in the U.S.

As part of the proposed process, transmission providers would be required to develop long-term scenarios, including accounting for high-impact, low-frequency events such as extreme weather.

Transmission providers would also be required to consider an expanded list of benefits related to proposed transmission infrastructure over a 20-year period, marked from the date the infrastructure is sited. Additionally, they must select transmission plans that most efficiently or cost-effectively meet the identified transmission need. The draft NOPR also proposed to require that public utility transmission providers more fully consider dynamic line ratings—as opposed to static line ratings that are currently used—and advanced power-flow control devices in regional transmission planning. Dynamic line ratings, a concept that has been in discussion for a long time, refers to classifying the capacity of a transmission line based on real-time, granular data, as opposed to a static rating that only accounts for heat and other factors. This allows transmission operators to maximize power flows over transmission lines.

Danielle Powers, a Senior Vice President and Board Member at Concentric Energy Advisors and a former employee of both an investor-owned utility and ISO New England, points out that very few proposed high-voltage transmission projects have been constructed in recent years, mostly due to local opposition, she said. The FERC is attempting to address this issue by requiring increased state involvement in transmission planning and cost allocation. It remains to be seen if this will lead to more support for new transmission at the state level.

“I know what they’re trying to accomplish,” Powers said. “I think they’re thinking: ‘if we get the states more involved, they’ll be able to be better informed and maybe have some role in garnering more local support.’ I think that is a high hurdle.”

States already participate in transmission siting because it is under their jurisdiction. State regulators as well as the public have also been wary of federal intervention when siting large transmission facilities that, in some cases, do not provide local benefits.

Regarding federal rights of first refusal, the draft NOPR proposes to amend Order 1000 “to permit the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of the transmission facilities.” This means that incumbent transmission providers will be permitted a federal right of first refusal as long as the facilities are jointly owned with unaffiliated, non-incumbent entities.

The NOPR would partially resurrect a federal right of first refusal that previously had been granted to transmission providers but was removed by Order 1000. Order 1000 required that public utility transmission providers eliminate a federal right of first refusal for an incumbent transmission developer with respect to entirely new facilities selected in a regional plan for purposes of cost allocation. But the Order 1000 right of first refusal elimination does not apply to local transmission facilities built solely within an incumbent provider’s footprint or to incumbents building, owning, and recovering costs of upgrades to its existing facilities. Order 1000 also does not remove or limit an incumbent provider’s use and control of its existing rights-of-way.¹

In the new NOPR, FERC noted that there were also exemptions from the right of first refusal for reliability projects with an immediate need. FERC said that recent transmission investment trends suggest that despite increased investment in transmission facilities overall. However, in many planning regions there has been comparatively limited investment in transmission facilities selected in a regional plan for purposes of cost allocation as the result of a competitive process. Transmission development has largely been concentrated in local transmission projects that are generally not subject to competitive transmission development processes.

During transmission planning, regional transmission organizations or independent system operators issue requests for proposals for competitive transmission projects. Transmission developers respond to the requests with project proposals, some of which are approved for interconnection studies. If the projects meet certain thresholds, they are included in regional transmission plans and once projects are selected, transmission developers move forward with getting state permits.

“Taken together, the reforms proposed in this draft NOPR would work to remedy deficiencies in the Commission’s existing regional transmission planning and cost allocation requirements,” FERC said in a statement. “This, in turn, would fulfill the Commission’s statutory obligation to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential.”

In light of the longer planning horizons, the draft NOPR also proposes to eliminate a construction work in progress financial incentive (CWIP Incentive) for transmission facilities that allows transmission providers to recover investment costs as the projects are being built. In the NOPR, FERC states that it had previously found the CWIP Incentive to be beneficial to ease financial pressures by providing up-front regulatory certainty, rate stability, and improved cash flow, which can result in higher credit ratings and lower capital costs. But those are benefits to corporations and shareholders, not utility customers who are not yet enjoying the benefit of the new facilities. If the facilities are not placed into service, ratepayers shoulder the cost without gaining any benefit, the NOPR says.

“We are concerned that the CWIP Incentive, if made available for Long-Term Regional Transmission Facilities, may shift too much risk to consumers to the benefit of public utility transmission providers in a manner that renders Commission-jurisdictional rates unjust and unreasonable,” FERC said.

One forum addressing the NOPR is the FERC Joint Federal-State Task Force on Electric Transmission, which includes state regulators from around the country and has several meetings remaining this year. The task force was formed in a partnership between FERC and the National Association of Regulatory Utility Commissioners.

FERC is taking comments on the NOPR and encouraged commenters to identify improvements to the proposal that will support development of more efficient and cost-effective transmission facilities (R22-32). Comments are due 75 days from date of publication in the Federal Register, and reply comments are due 30 days after the initial comment deadline. Members of the public requiring assistance in filing comments should email FERC’s Office of Public Participation at opp@ferc.gov, the agency said.

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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

¹ FERC’s Order 1000 distinguished between incumbent transmission developers and nonincumbents. An incumbent developer builds transmission within its own retail distribution territory or footprint, while nonincumbents are either developers that have no retail distribution territory or footprint, or a utility transmission provider that proposes a transmission facility outside its existing territory or footprint.

Published: May 13, 2022

By: Concentric Staff Writer

Momentum is growing towards a wider wholesale electricity market in the Western U.S., but a rocky history and issues around who would govern such a market are among the many challenges to this effort.

Many of the utilities in the West operate outside an independent system operator (“ISO”) or regional transmission organization (“RTO”), but the need to integrate increasing amounts of renewable energy resources in western states is swinging the conversation back to a western RTO.

That conversation has heated up since last summer when the Federal Energy Regulatory Commission—which regulates wholesale energy markets—held a technical conference on  resource adequacy in the Western Interconnection. At that conference, Commissioner Alison Clements noted that extreme weather events attributed to climate change and the West’s changing energy resource mix is bringing more urgency to the western RTO debate. She also noted that historically, the federal government has allowed western grid planners to operate with relative freedom from burdensome mandates coming from  Washington D.C.

“The urgency of efforts towards broader regional integration has changed in the last year, even in the last six months,” Clements said. “Shared goals” and assuring reliability in the face of increased weather threats, as well as new state mandates and protecting consumers are other drivers towards regional integration, she added.

Clements added that she and FERC Chairman Richard Glick “believe that well-designed regional markets, in this case designed by westerners for westerners is the best path forward to protect customers and ensure reliability while addressing resource adequacy concerns and the other serious challenges facing the West.”

Last June, nine former FERC commissioners wrote to current agency members encouraging exploration of a western RTO, saying ISOs and RTOs “provide compelling platforms for renewable energy development and are achieving considerable consumer benefit.” More than 80 percent of renewable resources have been placed in regions with organized markets, the letter says. It was signed by former commissioners Nora Mead Brownell, James J. Hoecker, William Massey, Elizabeth Moler, John Norris, Robert Powelson, Branko Terzic, Jon Wellinghoff, and Pat Wood.

States throughout the West are exploring participation in an RTO. For example, Nevada passed legislation last year forming a working group to study the implications of the state’s utilities joining an RTO. A December, 2021 study by the Colorado Public Utilities Commission found that enhanced market participation through regional collaboration could save the state’s utilities four to five percent in costs per year, or about $230 million annually. And the Utah Governor’s Office of Energy Development, in partnership with State Energy Offices of Idaho, Colorado, and Montana received a grant from the U.S. Department of Energy to facilitate a state-led assessment of organized market options, a study that will last more than two years.

The discussion around a Western Interconnection-wide RTO is occurring as existing entities such as the California Independent System Operator (“CAISO”) and Southwest Power Pool (“SPP”) work to spread their footprints with regional balancing markets. These regional balancing markets do not include day-ahead power scheduling, a participatory governance structure, or other aspects of an RTO.

CAISO’s wider energy balancing market across the West is known as the Western Energy Imbalance Market (“EIM”), which CAISO recently announced has resulted in a cumulative $2 billion in benefits since its creation in 2014. In the first quarter of this year, the EIM resulted in more than $172 million in benefits to market participants, due to its ability to identify the least-cost resources to meet immediate power needs and manage transmission congestion, helping grid reliability, CAISO said.

CAISO is currently taking comments on a straw proposal to bring its existing day-ahead energy market across the EIM footprint, and by next year the EIM is due to have 22 utilities that serve about 80 percent of the electric load in the West. Expanding the day-ahead market is seen as an exploration towards a western RTO as it links CAISO with Northwest utilities such as the Bonneville Power Administration and others.

But the energy crisis of the early 2000s and the August 2020 blackouts in California, along with ideological and political rifts between the Golden State and other western states, have kept any regionalization of CAISO at bay. Leaders and market participants in other western states fear that an RTO operated by CAISO would spread many of California’s issues such as blackouts across the West. Legislation to regionalize CAISO has been introduced at the state level in California but has historically sputtered due to opposition by labor unions over fears it would take jobs out of California, as well as environmental and public interest groups that say it would take the state’s energy planning out of state hands.

In addition to CAISO’s EIM, SPP formed the Western Energy Imbalance Service (“WEIS”) market in 2021, relying on its long history of operating a wholesale market across 17 states, and includes several participants.¹  SPP is currently working on broader market efforts. In July 2021, SPP officials approved policy-level terms and conditions for RTO expansion in the Western Interconnection. Western entities considering participation in the effort include Basin Electric Power Cooperative, Colorado Springs Utilities (“CSU”), Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Wyoming Municipal Power Agency, and the Western Area Power Administration (“WAPA”). WAPA said its evaluation of full RTO participation in the Western Interconnection includes its Upper Great Plains-West region, Colorado River Storage Project, and Rocky Mountain region. All those organizations except Colorado Springs Utilities have joined SPP’s WEIS, with CSU planning on joining the WEIS this year.

Neither CAISO nor SPP has yet introduced a formal proposal for a full western RTO, although SPP has an offering known as Markets+ that includes centralized day-ahead and real-time unit commitment and dispatch, transmission service, and other services for entities that don’t yet want to join a full RTO.

An additional effort toward western energy market expansion is the informal Western Markets Exploratory Group (“WMEG”), dedicated to exploring additional market efficiencies in the West. Xcel Energy-Colorado, Arizona Public Service, Black Hills Energy, Idaho Power, NV Energy, Inc., PacifiCorp, Platte River Power Authority, Portland General Electric, Puget Sound Energy, Salt River Project, Seattle City Light, and Tucson Electric Power are members of the group, which was created in October 2021.

According to a blog post by PacifiCorp, the WMEG is exploring the potential for a staged approach to new market services, including a day-ahead market, transmission system expansion, and other power supply and grid solutions. PacifiCorp said the effort aims “to identify market solutions that can help achieve carbon reduction goals while supporting reliable, affordable service for customers.” Many of the companies in the WMEG also participate in CAISO’s EIM, but the WMEG discussions will not affect participation in that market in the short term, since WMEG is a long-term initiative.

Another west-wide effort is the Western Resource Adequacy Program (“WRAP”), operated by the Northwest Power Pool. The WRAP seeks to increase reliability for western entities “while maintaining existing responsibilities for reliable operations and observing existing frameworks for planning, purchasing, and delivering energy”.² The effort includes 26 market participants representing an estimated peak winter load of 65,122 MW and an estimated peak summer load of 66,768 MW across 10 states and one Canadian province.³

With so many efforts underway to coordinate planning and generation dispatch across the West, establishing a Western Interconnection-wide market seems inevitable. Such a complex process requiring so much coordination among Western entities will be a challenge, but with so much market development underway and federal support, the effort appears to be gaining serious momentum.

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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

¹ Basin Electric Power Cooperative; Colorado Springs Utilities (effective August 2022); Deseret Power Electric Cooperative; Municipal Energy Agency of Nebraska; Tri-State Generation and Transmission Association; Western Area Power Administration (Upper Great Plains West, Rocky Mountain Region. Colorado River Storage Project); and Guzman Energy.

² https://www.westernpowerpool.org/news/wpp-to-be-led-by-transmission-expert-sarah-edmonds

³ https://www.westernpowerpool.org/news/wrap-announces-full-participation-of-phase-3a

The American Council on Renewable Energy (ACORE) commissioned a report by Concentric entitled How Transmission Planning & Cost Allocation Processes Are Inhibiting Wind & Solar Development in SPP, MISO, & PJM.

Click here to access the report on ACORE’s website.