Right of First Refusal – the Battle Intensifies

Published: May 12, 2023

By: Danielle Powers, Executive Vice President

There is no question that expanding the electric transmission system is a key factor in achieving the nation’s clean energy goals. The most efficient way to ensure that this happens, however, is being strongly debated.

FERC Order 1000 established reforms in transmission planning and cost allocation, and eliminated the Right of First Refusal (ROFR) for those incumbent utilities involved in regional or inter-regional infrastructure construction, with limited exceptions.1 In Order 1000, FERC reasoned that by eliminating long-standing monopolies, competition would be created, and innovation and cost savings would result. In eliminating utilities’ monopoly over regional transmission, however, FERC expressly left it to states to enact their own ROFR laws.

Utilities in Kansas, Missouri, Oklahoma, Mississippi, and Montana have successfully persuaded lawmakers to prioritize ROFR legislation. Indiana recently passed ROFR legislation, and legislation is anticipated in other midwestern states this year. States including North and South Dakota, Nebraska, Texas, Iowa, and Michigan have ROFR laws in place.

ROFR issues are also being re-examined at the federal level. Questions around the effectiveness of competition in transmission have prompted the FERC to consider giving incumbent utilities the right to build regional transmission if they partner with one or more unaffiliated, non-incumbent partners.

Critics of the ROFR argue that it can limit competition and innovation in the industry. By granting the incumbent transmission provider the first opportunity to continue providing service, it can create a barrier to entry for other providers who may be better suited to meet the needs of the market. Additionally, the ROFR can limit consumers’ ability to access alternative sources of energy and limit the development of renewable energy sources.

These arguments have recently carried the day in Iowa, where the battle over who should be able to build and own the regional transmission projects necessary to support grid reliability and the shift toward renewable energy is currently playing out.

The Iowa Supreme Court recently halted a 2020 order giving incumbent utilities in Iowa the right of first refusal to build proposed transmission projects. Stating that the 2020 law would stifle competition and harm the business interests of out-of-state companies, the Iowa Supreme Court sent the case back to the district court to decide whether the ROFR is unconstitutional. The temporary injunction affects five transmission projects totaling about $2.64 billion that ITC Midwest, MidAmerican Energy and Cedar Falls Utilities intend to build in Iowa. The projects are part of the Midcontinent Independent System Operator’s Long Range Transmission Planning Tranche 1 projects, approved last year.

The battle over who builds the grid of the future will continue to be fiercely debated. Protracted debate, however, risks the grid transformation necessary to enable a clean energy future.

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.

1 An incumbent utility is defined as an entity that develops a transmission project within its own retail distribution service territory or footprint.

Hydrogen is an Increasing Element of U.S. Energy and Transportation

Published: March 16, 2023

By: Concentric Staff Writer

It is no secret that hydrogen, the most abundant and lightest element in the universe, is also one of the most powerful. Research in recent years is moving closer towards expanding its commercial applications to power generation and transportation.

Hydrogen has many applications and is already in widespread use in industrial processes such as refining petroleum, treating metals, making fertilizer, and processing foods, according to the U.S. Energy Information Administration. It is even used by the National Aeronautics and Space Administration for rocket fuel and fuel cells that power spacecraft. Now, new efforts are underway aimed at making hydrogen an everyday part of the power sector and the U.S. vehicle fleet.

The Inflation Reduction Act (“IRA”), passed in the summer of 2022, has created a surge in the development of the hydrogen resource. In December 2022, the U.S. Department of Energy (“DOE”) responded to concept papers submitted for a program created by the IRA, known as the Regional Clean Hydrogen program. DOE, in a news release, said the program “will be a central driver in helping communities across the country benefit from clean energy investments, good-paying jobs, and improved energy security—all while supporting President Joe Biden’s goal of a net-zero carbon economy by 2050.”

DOE describes hydrogen hubs as a network of clean-hydrogen producers, consumers, and “connective infrastructure in close proximity.” The 79 concept papers from states and their partners submitted to DOE flow from the $7 billion funding opportunity the agency issued in September 2022. The concept papers requested nearly $60 billion total, eight to nine times the amount of the funding solicitation, and proposed almost $150 billion in private capital for projects with many different technologies and in every region of the country. DOE said it sought the best hydrogen-based solutions possible and the concept paper solicitation was aimed at getting a better understanding of what final funding applications might look like. The concept papers were judged based on a series of criteria, including qualifications, experience, and capabilities of the applicant; expected contributions toward a national hydrogen network; plans to develop production, end-use, and connective facilities; and community benefits.

One of the concept papers that received an encouragement letter from DOE is the Western Interstate Hydrogen Hub, a project between the states of Colorado, New Mexico, Utah, and Wyoming. The four states are keen on developing hydrogen as a safe, clean, and sustainable energy resource.

“This strategy will help to meet the region’s diverse energy needs and policy goals, including reducing greenhouse gas emissions, using a broad range of feedstock to develop hydrogen, ensuring economic competitiveness, and supporting communities on the front lines of the energy transition,” the four-state coalition said in a December press release. According to DOE, an “encouragement” letter does not mean a project will be selected, and those that received “discouragement” notices are still free to apply. The encouragement letters mean the applicant is “on the right path” to submitting a full application, and the agency said there will be heavy competition for the funding, even among entities that received encouragement letters.

Other hydrogen hub projects selected by DOE for letters of encouragement include efforts in the Northwest, one by Obsidian Renewables and another by the governments of Washington and Oregon; the Halo Hub, a partnership between Arkansas, Louisiana, and Oklahoma; the Appalachian Regional Clean Hydrogen Hub in West Virginia, supported by that state, Kentucky, Ohio, and Maryland; the HyVelocity Hub in Texas; and others.

Hydrogen is also being explored for electricity generation with several projects underway to convert former natural gas-burning plants to burn hydrogen. One is the 485-MW Long Ridge Energy Generation Project in Ohio, which will run on a 95-percent natural gas, 5-percent hydrogen blend in a gas turbine with plans to burn pure hydrogen eventually. Intermountain Power Agency in Utah also plans to convert to hydrogen from coal, and there is a plan to convert the 830-MW Scattergood Generating Station in Los Angeles to hydrogen from natural gas. The Los Angeles City Council on Feb. 8 in a 12-0 vote approved allowing the Los Angeles Department of Water & Power (“LADWP”) to move forward with a competitive bidding process for the project, but also approved a separate resolution requiring LADWP to closely communicate with the council on its progress.

However, hydrogen is not popular with most environmental groups—Food & Water Watch (“F&WW”) has indicated its opposition to the hydrogen hubs program. Environmental groups say it is an effort by the fossil fuel industry to support natural gas, which is used to produce “blue hydrogen.” Separately, “green hydrogen” is hydrogen produced from renewable resources. According to French utility company Engie, the most common way to create green hydrogen is electrolysis using water and electricity produced from non-carbon-emitting resources, or using another technique known as pyro-gasification in which heat is applied to biomass such as wood or agricultural waste to produce a complex gas from which hydrogen is extracted.

F&WW, which also opposes the Scattergood repowering, says corporations are pushing hydrogen to keep fossil-fuel facilities alive and that burning hydrogen produces smog through the production of nitrogen oxides. Turbine manufacturer Mitsubishi says its hydrogen turbines that burn 70 percent hydrogen and 30 percent natural gas produce about the same carbon dioxide emissions as burning straight natural gas.

Hydrogen fuel cells, which are already being used in commercially available vehicles, generate electricity by combining hydrogen and oxygen to produce electricity, water, and heat in a process similar to that of a battery. Fuel cells, depending on size, are used for a range of applications, from consumer products such as laptop computers and cellphones to power grids, backup generation, and microgrid applications.

At the end of October 2021, there were about 166 operating fuel cell electric power generations at 113 facilities making up about 260 MW of generation capacity. The largest such facility is the 16-MW Bridgeport Fuel Cell in Connecticut, followed by the Red Lion Energy Center in Delaware, which has five fuel cells totaling 25 MW.

On the transportation side, hydrogen is not only being explored for ground-based vehicles, but also airplanes. ZeroAvia, founded in 2018, is focused on repowering existing aircraft with electric motors, fuel cells, and hydrogen. It has signed memoranda of understanding with several aircraft manufacturers to attain help in certifying the technology. ZeroAvia hopes to develop a 600-kilowatt powertrain by 2025 for an aircraft with 19 seats able to fly up to 300 nautical miles. In 2027, it hopes to launch a modular 2- to 5-megawatt drivetrain, able to retrofit aircraft with up to 80 seats for flights up to 700 miles, and higher-output drivetrains in later years.

Hydrogen vehicles utilize electric motors powered by hydrogen fuel cells. Toyota has been a leader in this area, with several models publicly available. However, unlike electric vehicles, hydrogen vehicles still have a relatively high fuel cost per gallon of hydrogen, and a higher up-front purchase price, and the hydrogen-station network needed to support these vehicles is still in its nascent stages.

According to DOE, transporting hydrogen requires either a pipeline network of cryogenic liquid tanker trucks or gaseous tube trailers. Development of pipelines must be in areas with substantial, stable hydrogen demand in the area of hundreds of tons per day. Liquification plants, tankers, and trailers are deployed in areas where demand is at a smaller scale or emerging. Additional infrastructure is needed at the point of hydrogen use, including compression, storage, dispensing, metering, and contaminant detection and purification technologies.

Several companies are capable of delivering bulk hydrogen today, DOE said, and some infrastructure is in place because of its usage in industrial applications, but more research and development, expansion of the supply chain, and new deployments will be needed before it is in widespread application. Some of the biggest challenges are in the areas of reducing cost, increasing its efficiency, maintaining hydrogen purity, and minimizing leakage from infrastructure, the agency said. The necessary infrastructure will depend on the region and the type of market—urban, interstate, or rural—but these options will also evolve as demand grows and technology improves. If all the various pieces fall into place, hydrogen might enjoy a long future as a vital power source in the U.S. energy mix.

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.

Summary of Comments on the Proposed Massachusetts Forward Clean Energy Market

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.

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.

U.S. DOE, EPA to Collaborate on Reliability During Energy Transition

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.

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.

Small Modular Reactors are an Emerging Technology Facing Many Challenges

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.

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.

Proposed Federal Transmission Rules Create Optimism, Skepticism

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.

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.


An Organized Western Electricity Market – Who Would Run it and What are the Challenges?

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

New Transmission can Provide a Path for Renewables, but Hurdles are Significant

Published: October 25, 2021

By: Concentric Staff Writer

There is growing recognition among policy makers, industry, and environmental groups that more electric transmission lines will be needed across the United States to achieve the buildout of renewable energy infrastructure required to meet climate change goals.

The federal government along with states recently moved forward with major new efforts to build transmission infrastructure, but these initiatives have many hurdles that could cause them to sputter, as was the fate of previous attempts by the federal government to take more control over transmission siting.

The Federal Energy Regulatory Commission (FERC) took a major step toward reforming transmission planning, recently closing out its comment period from industry, state regulators, regional market officials, and others on its advance notice of proposed rulemaking (ANOPR) issued in July. The FERC proceeding, “Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection” will update FERC’s well-known Order No. 1000 on transmission and cost allocation by utilities, issued by the Commission in 2011.

“The electricity sector is transforming as the generation fleet shifts from resources located close to population centers toward resources, including renewables, that may often be located far from load centers,” FERC staff said in a presentation on the ANOPR. “The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources are creating new demands on the transmission system.” The Commission added that the priority in regional transmission planning is ensuring just and reasonable rates and maintaining reliability as the resource mix shifts to more renewables.

One prominent group, the Electric Power Supply Association (EPSA), which is the national trade association representing competitive power suppliers, told FERC in its filed comments that it is critical “that any reforms to transmission policies leverage the Commission’s commitment to competition to ensure that cost-effective transmission investments are signaled and supported by planning, cost allocation, and/or interconnection processes, including the use of competitive procurement processes. FERC’s previous landmark orders on transmission issues under its authority have been successful by ensuring that non-discriminatory open access transmission service supports and promotes competitive power markets.”

There was also a major new effort on state-federal cooperation for transmission planning in June: FERC’s creation of the Federal-State Task Force on Electric Transmission. The task force will hold its first meeting Nov. 10 in Louisville, Kentucky, a location and date chosen to coincide with an annual meeting of state regulators from around the country. FERC said this is the first in a series of such meetings, and an agenda will be issued Oct. 27. FERC recently selected 10 state regulators to the task force that were nominated by the National Association of Utility Regulatory Commissioners (NARUC).1

FERC is accepting agenda topics for the November meeting from interested parties (AD21-15). FERC notes that the development of new transmission infrastructure raises a host of issues, representing an area ripe for federal-state coordination and exploration by the task force.

The goal of the task force is to identify barriers to the planning and development of new transmission in order to facilitate achievement of state and federal policy goals such as renewable portfolio standards. The task force will also explore ways for states to use FERC-jurisdictional planning processes to achieve state policy goals. It will examine methods for states to voluntarily coordinate to develop regional transmission solutions and identify possible reforms to FERC regulations regarding planning and cost allocation of transmission projects.  Additionally, the task force will examine ways to connect resources more quickly to the electric grid and make transmission more cost-effective through enhanced state and federal coordination.

A large-scale effort by the federal government aimed at developing new transmission infrastructure ran aground more than 15 years ago, illustrating the tremendous difficulties in siting massive new transmission facilities, including state and local opposition. The U.S. Congress gave the Department of Energy (DOE) the authority to create “National Interest Transmission Corridors” in the Energy Policy Act of 2005. The legislation gave the DOE power of eminent domain to purchase property needed to build transmission if state and local government failed to issue permits.

But the effort received pushback from state and local governments, and ultimately the designation of two corridors in the Mid-Atlantic and Southwest in 2007 and a congestion study done by DOE in 2006 were vacated by the U.S. Ninth Circuit Court of Appeals in California after a lawsuit by the Wilderness Coalition against DOE. The court ruled that DOE had not adequately consulted with states and had not considered environmental impacts.

Any new effort by FERC could run up against the same opposition from some states. For instance, Arizona Corporation Commission Chairwoman Lea Márquez Peterson wrote to the U.S. Congress in July, expressing concern over a similar national-interest transmission corridor designation within the federal infrastructure bill. She objected to any involuntary regionalization of the Western electricity grid, pointing to blackouts in California last year and in Texas earlier this year.

“Taking the opportunity to provide direct public engagement and involvement in the process away from Arizona’s local leaders and residents, in order to send it to federal bureaucrats in Washington, DC, would only exacerbate the objections that communities already have for the siting of transmission lines,” Márquez Peterson said in the letter. “It’s hard enough to convince citizens to support transmission lines through their communities when the siting process takes place locally, let alone to convince them to support a project that will be heard and decided in Washington, DC.”

The federal-state power struggle is as old as the United States itself, and modern transmission-system planning is no different, leaving the federal government with a challenging path ahead to get more transmission built and move renewable energy around the country.

For inquiries related to this article, please contact info@ceadvisors.com.

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 The task force includes the four current members of FERC—Chairman Richard Glick, Allison Clements, James Danly and Mark Christie—as well as the 10 state commissioners nominated by NARUC earlier this year. The task force is chaired by Glick, with two state commissioners appointed to five different regional conferences: Mid-Atlantic; Mid-American; New England; Southeastern and Western. State commissioners on the task force include Gladys Brown Dutrieuille, Chair of the Pennsylvania Public Utility Commission; Jason Stanek, chair of the Maryland Public Service Commission; Andrew French, chair of the Kansas Corporation Commission; Dan Scripps, chair of the Michigan Public Service Commission; Riley Allen, chair of the Vermont Public Utility Commission; Matthew Nelson, chair of the Massachusetts Department of Public Utilities; Kimberly Duffley, chair of the North Carolina Utilities Commission; Ted Thomas,  chair of the Arkansas Public Service Commission; Kristine Raper, chair of the Idaho Public Utilities Commission and Clifford Rechtschaffen, a member of the California Public Utilities Commission.

Energy Storage Set for Massive Growth on the U.S. Grid

Published: September 23, 2021

By: Concentric Staff Writer

The presence of energy storage—dominated by lithium-ion battery technology—is surging across the U.S. electricity grid, particularly in the West, driven by new rules at the federal level and the need to balance renewable generation.

A wave of solar and wind energy coming onto the grid, plus escalating decarbonization efforts in the sector, are bolstering new installations of storage, which helps balance the grid by storing energy in the early afternoon for use in the evening. One of the hottest markets for energy storage is California, where a preponderance of renewables has led grid operators and state lawmakers to push storage as a solution.

The amount of energy storage in the California Independent System Operator’s interconnection queue has skyrocketed from 2.6 GW in June 2014 to 69.2 GW in June 2020 and 147 GW in July of this year, CAISO data shows. According to CAISO staff presentations and comments at a recent Board of Governors meeting, most projects in the interconnection queue are not actually constructed due to lack of financing or other reasons, leading to discussions among the ISO’s management as to how to make the queue process more efficient.

The vast majority of new storage due to come online in California is battery energy storage, with a few GW of pumped hydro storage mixed in. Planned battery storage is almost evenly split between stand-alone energy storage projects and hybrid projects that pair storage technology with generation, usually solar. Areas with a large energy storage presence include Kern County, an oil and gas producing area; Riverside County; Los Angeles and Orange Counties; San Francisco; and San Diego. Storage output crested 1 GW on the CAISO grid in early August for the first time in history. Storage reaches maximum charge level around 2 p.m. when solar is peaking and then typically discharges energy in the critical 7-9 p.m. period when the grid is most stressed with high demand after the sun goes down and solar is no longer producing, CAISO said.

In a February report on energy storage, the North American Electricity Reliability Corp. (“NERC”) noted that the benefits of storage technology include fast-ramping support for the grid when solar begins to decline in evenings, rapid frequency response, and assistance with addressing operational uncertainty caused by adding large amounts of renewables to the grid.

In the report prepared with the Western Electricity Coordinating Council, NERC said that bulk energy storage systems “are projected to grow at an increasing pace across North America.” Advances in technology, cost reductions, and new rules at the federal level and within wholesale energy markets are also driving the technology, NERC said. The organization, which enforces mandatory reliability standards, created an inverter-based working group to develop guidelines for the integration of energy storage systems. Strategically located battery storage systems could help prevent blackouts, the organization said.

According to the report, entitled “Impacts of Electrochemical Utility-Scale Battery Energy Storage Systems on the Bulk Power System,” existing NERC reliability standards adequately reflect battery storage as a generator, ensuring that the NERC transmission-planning performance requirements, plus model and data standards, are applicable to the current number of storage systems on the grid. However, data on battery storage tends to be non-uniform and lacking in consistency among reporting entities, which will require better reporting mechanisms for energy storage data, the organization said.

“Because battery storage is an emerging technology, the development of utility-scale battery storage has lagged the integration of renewable resources,” the NERC report says.

The storage industry got a major boost in February 2018 when the Federal Energy Regulatory Commission, which regulates the bulk power system and wholesale energy markets, issued its landmark Order No. 841. The rule requires regional transmission organizations and independent system operators around the country to remove barriers to participation of electric storage resources in their capacity, energy, and ancillary service markets.

Each RTO and ISO in the U.S. was required to make compliance filings under the order, which mandated them to establish a participation model of market rules that recognizes the physical and operational characteristics of electric storage resources and facilitates their participation in the markets. The participation models must ensure that a resource is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing in the RTO/ISO markets, and that a resource can be dispatched and can set the wholesale market clearing price as both a wholesale seller and buyer. The participation models need to account for the physical and operational characteristics of energy storage resources through bidding parameters or other means. FERC has established a size requirement for participation in RTO/ISO markets that does not exceed 100 kW.

FERC rejected rehearing requests to Order 841 from state utility commissions that said storage integration was a state matter, and in July 2020 a federal appeals court upheld FERC’s Order No. 841, rejecting arguments that states should be free to control energy storage participation. Petitioners included the National Association of Regulatory Utility Commissioners, the American Public Power Association, the National Rural Electric Cooperative Association, Edison Electric Institute, and American Municipal Power, Inc.

“Because the challenged Orders do nothing more than regulate matters concerning federal transactions – and reiterate ordinary principles of federal preemption – they do not facially exceed FERC’s jurisdiction under the Act,” the U.S. Court of Appeals for the D.C. Circuit said in its decision.

Recognizing the limitations of four-hour battery storage technology, the U.S. Department of Energy launched a “Long-Duration Energy Storage Shot” research initiative. The goal of the shot is to “accelerate breakthroughs of more abundant, affordable, and reliable clean energy solutions within the decade,” DOE said. Having more long-term storage in place will help the country tackle the remaining barriers to addressing climate change and reach the Biden Administration’s goal of net-zero carbon emissions by 2050 more quickly while creating jobs, the agency said.

With new efforts at the grid operator level and at the federal government to integrate and develop new storage technologies, the resource appears to be here to stay on the U.S. grid and is poised to play a major role in integrating renewables and meeting climate goals.

For inquiries related to this article, please contact info@ceadvisors.com.

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.

How Transmission Planning & Cost Allocation Processes Are Inhibiting Wind & Solar Development in SPP, MISO, & PJM

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.

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