By: Concentric Staff Writer

Published: November 28, 2023

This winter could be a difficult season for the bulk electric system across large portions of the United States, according to national reliability officials.

Memories and lessons from extreme weather events such as winter storms Uri and Elliott—in 2021 and 2022 respectively—linger for industry and regulators due to electric grid failures and all that followed. And there is much evidence that the U.S. grid is not adequately equipped for the upcoming frigid conditions of winter.

A new report from the North American Electric Reliability Corporation (NERC) says that a large swath of the grid across the country is at risk of short electricity supplies this winter, particularly power plants fueled by natural gas. Natural gas freeze-ups have plagued systems from the Northeast to Texas in recent years, as was the case during polar vortexes and other events such as Winter Storm Uri in February 2021.

NERC’s Winter Reliability Assessment noted that in recent years more than 20 percent of U.S. generating capacity has been forced offline during winter reliability events when severe cold hits areas that don’t usually have it.

The natural gas production, transportation, and storage system, along with a large part of the electric grid, are a “single interconnected energy delivery system” extending from the natural gas wellhead to the end-use electricity customer. Natural gas supplies are key to the operation of this system, while electricity likewise has an impact on the compressors and other critical equipment. Meanwhile, disruptions to these systems can have “devastating” effects on the public, as demonstrated in the winter storms Elliot and Uri, when freeze-ups paralyzed mechanical and electric systems, the report says.

The areas at greatest risk encompass a large part of the U.S. including the Midcontinent Independent System Operator region covering 15 states; the 14-state PJM Interconnection region in the Mid-Atlantic; New England; the SERC region in the Southeast covering 16 south and southeastern states; the Southwest Power Pool region covering all or portions of 11 states in the central part of the country; The Electric Reliability Council of Texas; the Canadian provinces of New Brunswick, Nova Scotia, Manitoba, Saskatchewan, Quebec; and parts of Maine.

The crux of the matter is that reliability is threatened, and conditions are most challenging when the temperatures are low, demand is high, and people head inside to use electricity and heat. Natural gas is a necessary element to keep the electric system operating due to its critical role in power plant operation and heating, but the flow of gas is subject to many complications.

“Fuel assurance is vitally important to meeting winter electricity demand across North America. Natural-gas-fired generator availability and output can be threatened when natural gas supplies are insufficient or when the flow of fuel cannot be maintained,” NERC said in the report. “During Winter Storm Elliott, natural gas production rapidly declined with the onset of extreme cold temperatures, contributing to wide-area electricity and natural gas shortages.”

The blizzards, winds, snow, and low temperatures during Winter Storm Elliott hit the majority of the U.S. and portions of Canada, plunging millions into outages and causing dozens of deaths. The event was marked by widespread outages of natural gas-fired generation. Outages also affected wind, coal, solar, nuclear, and other resources such as hydroelectric and biomass.

Regarding this winter, in New England, there is concern as to whether there will be sufficient resources for extreme cold, given the existing generation mix, fuel delivery infrastructure, and expected fuel arrangements, NERC said. This is despite considerable effort to replenish stored fuels such as fuel oil and liquified natural gas.

ISO-New England is offering fuel security incentives such as “The Inventoried Energy Program,” which is voluntary and is designed to pay parties that maintain energy for their assets during periods of extreme cold when winter energy security is most stressed.

A cold-weather event leading from the Mid-Atlantic (PJM) to southern areas (SERC-East and SERC-Central) could lead to energy emergencies, the report says. This is due to forced outages of generators and spiking demand, which has risen in recent years while there has been little change in resources since Winter Storm Elliott. There are adequate resources for normal conditions but less so for extreme conditions, NERC said.

The U.S. West, stretching from the Rocky Mountains to the Pacific Ocean, is seen as having adequate supply when winter temperatures hit, but there could be a shortage of 10 GW during peak demand in the Northwest under certain conditions, such as high demand paired with generator outages and low hydroelectric output.

In the Western Electricity Coordinating Council (WECC), resources are expected to be adequate, but this region is among those that have peak electricity demand in summer, when air conditioning surges. WECC’s region includes all or portions of 14 western U.S. states stretching from the Canadian border to Mexico, including California.

In the Northwest, there is some risk this winter under certain scenarios in a region that has been “mixed-season peaking” according to NERC. Power is expected to be adequate in peak demand hours under all conditions other than an “extreme combined scenario,” which would require 5.3 GW of imports in certain peak load scenarios. The level of imports is expected to be adequate, depending on conditions in surrounding areas.

In Texas, the threat of continued cold weather continues in areas where infrastructure has not been retrofitted for extreme cold. There has also been robust load growth in Texas that is not being met with the expansion of dispatchable resources. ERCOT is taking steps, including a new fuel supply service that is intended to supplement natural gas capacity during energy emergencies.

In MISO’s territory, new wind and natural-gas generation has been installed, and the lives of older fossil-fuel plants extended. MISO implemented a seasonal resource adequacy construct to more effectively evaluate risks and resources according to variances at different times of the year.

The Southwest Power Pool has an anticipated reserve margin of 38.8 percent, about 30 percentage points lower than last winter, driven by higher peak demand and fewer resources. Normal forecast peak demand and expected outages are expected to be covered, but extreme weather could cause energy emergencies.

The NERC report includes a series of recommendations—reliability coordinators, balancing areas, and gas system transmission operators should review seasonal operations plans and protocols for communicating potential supply shortfalls in anticipation of generator outages and extreme demand. These same entities should implement “essential actions” identified by NERC in its Level 3 alert, dubbed “Colder Weather Preparations for Extreme Weather Events-III” and undertake recommended weatherization steps prior to the winter season.

Balancing areas should also be aware of the potential for short-term forecasts to underestimate the electrical load that could occur during cold-weather events and be prepared to take early action to manage deficiencies in electric supply reserves. Reliability coordinators and balancing areas should also implement generator fuel surveys to monitor fuel supplies and should prepare for potential supply shortfalls that could affect the readiness of power plants and other generation sources, the availability of fuel, load curtailment, and the ability for sustained operations during extreme cold.

State and provincial regulators should also assist grid operators before and during extreme cold, such as supporting environmental and transportation waivers and issuing appeals to the public to reduce gas and electricity usage.

There have been five cold-weather events that jeopardized electric grid reliability, triggering generation outages in the cold, sometimes requiring the shedding of load—cutting off electricity grid customers. During both winter storms Elliott and Uri, large swaths of the thermal generation fleet went offline.

“What has become clear is that the natural-gas-electric system has now become fully interconnected, each requiring the other to remain reliable (i.e., impacts on one system can impact the other),” NERC said. “These considerations should drive higher levels of coordination to ensure sustained reliable operation of this interconnected system.”

Complicating the picture for natural gas is the fact that infrastructure problems can affect the flow of fuel and production declines can occur even in areas where cold weather happens often. These problems are made more severe when cold occurs across large areas, spurring demand from local distribution companies and gas-fired generators.

Another factor is coal supplies for coal-fired power plants. Issues with rail transportation of coal have subsided as of the 2022-2023 winter season, but other complications could surface this winter. Drought conditions that affected the Missouri River and other waterways could restrict the transport of coal, and low water levels could impact generators that rely on water for once-through-cooling methods.

Extreme temperatures can also affect demand forecasting, which is essential for the reliable operation of the electric system, NERC said. Load forecasts are key inputs for resource-adequacy planning, coordination of seasonal outages, and day-ahead and real-time operational plans. The interaction of cold-weather patterns and the effect on end users are some of the most challenging issues, adding to winter reliability risk.

There can also be a wide range of demand in peaking areas from one year to the next, NERC said, adding that load forecasts for normal peak demand reflect the highest expected system load for an average winter.

In the MISO region, a list of measures, including load-modifying resources, non-firm energy transfers, energy-only resources, and certain internal transfers, are expected to maintain reliability. Extremely cold weather shows how critical resource adequacy and proper planning are necessary for all seasons, not just the summer, NERC said.

Generator fuel supplies are at risk during extended cold-weather periods, NERC said, a vitally important issue across the entire country.

Attempts to forecast load are getting more complex, and underestimating demand causes risks to reliability. Meanwhile, more irregular weather patterns such as strong winds, cold fronts, and precipitation can cause electricity demand to deviate significantly from forecasts. There may also be curtailment of energy transfers in periods of high energy demand. Reliability coordinators and balancing areas might curtail transfers for various reasons, but curtailments might alleviate an issue in one area while causing supply shortages or system issues in other areas.

The NERC Board of Trustees in June 2021 implemented new reliability standards that will be in place this winter, designed to increase coordination between system generators and operators. Other standards have been put in place flowing from the “FERC-NERC-Regional Entity staff report—The February 2021 Cold Weather Outages in Texas and Southcentral United States.” Approval by the NERC board will lead to filing with regulatory authorities and then industry implementation.

NERC surveyed the industry and found that winter preparations are on a “positive trend”, but freezing weather still causes concern. NERC has issued alerts to enhance readiness and reduce risk for the upcoming winter. Generation owners have taken steps to prepare their facilities to operate at extreme temperatures, but failures from past weather events are a concern. These include “improper heat tracing, frozen instrumentation and control equipment, generator circuit breaker tripping in low temperatures or low air pressures, and wind turbine blade icing,” NERC said.

NERC’s new assessment is ringing the alarm bells on electric grid reliability this winter but also offers solutions to what is expected to be another grueling test for the U.S. electricity grid.

NERC’s report offers reliability evaluations for each portion of the country: MISO: MRO-Manitoba Hydro; MRO-SaskPower; NPCC-Maritimes; NPCC-New England; NPCC-New York; NPCC-Ontario; NPCC-Québec; PJM; SERC-East; SERC-Central; SERC-Southeast; SERC-Florida Peninsula; SPP; Texas RE-ERCOT; WECC-Alberta; WECC-British Columbia; WECC-California/Mexico; WECC-Northwest; WECC-Southwest.

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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, related companies, or clients. 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

By: Concentric Staff Writer

Published: November 9, 2023

The International Energy Agency (IEA) is exploring different scenarios to reach global targets for greenhouse-gas emission reductions, performing detailed new research on the unprecedented level of build-out and investment that would be needed.

Larger, more robust, and smarter electric grids will be needed worldwide to transition modern societies to clean energy from fossil fuels, but the pace of growth needs to accelerate substantially, according to the new IEA report. The importance of electricity grids is growing, with major transitions happening, such as renewable energy, electric vehicles (EVs), and electric heating, IEA said in the report, “Electricity Grids and Secure Energy Transitions.” The report is meant to take stock of the world’s grids as they now stand and assess any signs that grids are not keeping pace with the new global energy economy, as well as analyze scenarios to meet zero emissions. There is a danger that grids will be bottlenecks to future efforts to move to clean energy and create energy security, the researchers said.

“Clean energy transitions are now driving the transformation of our energy systems and expanding the role of electricity across economies. As a result, countries’ transitions to net zero emissions need to be underpinned by bigger, stronger and smarter grids,” IEA said in an executive summary.

To achieve the energy and climate goals of various countries to be zero-greenhouse gas emitters, electricity usage worldwide must grow at a 20-percent faster rate than now, the report says. Expanded grids will be needed to deploy more EVs, and electric heating and cooling systems to scale up new technologies such as hydrogen production using electrolysis. A total of 80 million kilometers of grid infrastructure, the equivalent of the entire existing world-wide grid, must be added or refurbished to meet climate goals.

In an “announced pledges” scenario in which countries’ national energy and climate goals are met on time and in full, wind and solar must account for 80 percent of the total increase in global power capacity over the next 20 years, compared with less than 40 percent that has been added over the last 20 years, the report says. In IEA’s Net Zero Emissions by 2050 Scenario, wind and solar account for up to 90 percent of the global power supply increase.

“The acceleration of renewable energy deployment calls for modernizing distribution grids and establishing new transmission corridors to connect renewable resources – such as solar [photovoltaic] projects in the desert and offshore wind turbines out at sea – that are far from demand centers like cities and industrial areas,” the report says.

One pressing need is interconnection reform, as about 3,000 GW of renewable power projects—about half of which are in the advanced planning stages—are waiting in grid interconnection queues. This is equivalent to five times the amount of solar photovoltaic and wind capacity that was added globally last year, IEA said. Investment in renewables has nearly doubled since 2010, but global investments in grids themselves have remained at about $300 billion per year.

Delays in grid investment and refurbishment would substantially increase carbon dioxide emissions, leading IEA to develop a “grid delay case” in its research to explore what would happen if there were more limited investment, modernization, digitization, and operational changes.

Regulation of electric grids needs to be reviewed and updated so it supports not only new grids but improving current ones, and incentives should be put in place so grids keep pace with rapidly changing supply and demand, the report says. This means removing administrative barriers, rewarding good performance and reliability, and spurring innovation. Assessments of regulatory risk also need to improve “to enable accelerated buildout and efficient use of infrastructure.”

The 130-page report is divided into four chapters: “state of play,” “regulation and policy,” “identifying the gap,” and “policy recommendations.”

The “state of play” chapter notes that electricity grids have grown steadily over the past 50 years at a rate of about 1 million kilometers (km) per year, overwhelmingly in lower-voltage distribution networks, rather than higher-voltage transmission networks. More recently, there have been challenges in integrating renewable energy resources. Advanced economies are seeing investment but also long lead times for high-voltage transmission development, which signals that there are challenges to completing needed development. Investment has also been falling off in recent years with supply chain slowdowns even as demand and population grow, creating more risks for grid build-out. Grids play a central role in energy security, but grid congestion and delays in connecting renewable projects, including the supply chain issues caused by factors such as the COVID-19 pandemic and the war in Ukraine, are also causing impacts. For example, wait times for 50-MVA power transformers grew from a typical 11 months to more than 19 months due to materials and labor shortages, the report says.

“In short, we find evidence of multiple challenges that will need to be addressed to deliver the grids of the future,” IEA said.

Most grids are alternating current (AC), which has historically been composed of rotating generators such as thermal and hydroelectric plants, while new renewable resources connect to the grid mainly through electrical inverters. AC grids are popular because they are adept at changing voltage using long-distance transmission, which minimizes losses and allows transformers to be used to shift to lower voltages for local or regional distribution grids serving residential, commercial, and industrial customers.

However, direct current (DC) grids have certain advantages, such as in occasions when undersea cables are preferable and are used to serve multiple wind farms or markets, or cross-border interconnections and long-distance transmission from large hydro facilities are needed to reach demand centers. DC also offers grid stability and black-start capabilities.

Emerging markets and developing economies have built about 1.2 million kilometers of new transmission lines due to growing demand and access to electricity. Renewable policies have also led to new generation in places far from major load centers and have led to more countries dealing with interconnection issues. China accounts for one-third of the world’s new transmission facilities over the past ten years, or about half a million kilometers of transmission lines, used for purposes such as connecting energy sources from northern and western provinces to eastern load centers using ultra-high-voltage lines. India and Brazil are also rapidly expanding their grids, adding nearly 180,000 kilometers over the past ten years, about a 60-percent increase.

The age of grids varies by country, depending on historical development and varying levels of investment. The lifespan of grids, which are kept in service much longer than most facilities they interconnect, depends on the overloading and capacity, environmental factors, and the specific component. Transformers generally have a lifespan of 30 to 40 years, as do circuit breakers and other substation switchgear. Underground and undersea cables can last up to 50 years, and overhead transmission lines can last 60 years. More than 50 percent of grid infrastructure in advanced economies has been in service for longer than 50 years, and only about 23 percent is less than ten years old. However, in emerging and developing countries, about 40 percent of infrastructure is less than ten years old, and less than 38 percent is less than 20 years old.

The U.S., Japan, and some European countries have a higher proportion of their grids that are more than 20 years old. More than 50 percent of the countries in the European Union have grids more than 20 years old, which is about half their expected lifespan. Most new transmission in these countries has been built to access renewable generation. In Africa, Ghana, Kenya, and Rwanda have made significant investments in modernizing and expanding their grids.

Digitization of the world’s grids is also becoming “paramount,” according to the report, which says investment in digital technologies rose from about 12 percent of global investment a few years ago to about 20 percent in 2022. This is because of a need to manage distributed energy resources such as EVs, small-scale renewables, and electric heat pumps, as well as new players in the industry such as aggregators and demand response companies. Grid operators need digital technology for real-time monitoring and control of energy flows, especially in distribution grids, which saw 75 percent of global investment in 2022. The rise of distributed energy resources and other new technologies on the grid is requiring more precise study of power flows, the report says.

On the regulatory side, power grids are natural monopolies that are thus heavily influenced by regulations and policy, including entities that manage transmission and distribution systems, market structures, and market restructuring. Energy transitions, including climate change efforts, are driving the evolution of many of these regulations and policies.

Regulatory structures range from “cost of service,” where rules are set for companies to recover costs along with an allowed rate of return, or price-cap renumeration where there is a yearly cap that a grid operator can charge for each service or cluster of services. There is also a “yardstick competition” model where a grid operator’s service is compared with competitors and performance-based penalties and awards are assessed, as well as “output/performance-based” regulation where renumeration is based on monitoring the performance of service in order to encourage improvement in service. These varying regulatory models have different impacts on cost recovery and minimization, performance and operational efficiency, affordability, and quality of service.

Many national energy agencies and ministries are shifting to performance-based regulation since it spurs innovation and operational efficiency, the report says. A traditional regulatory approach, such as the “cost plus” framework, incentivizes capital expenditures even when operational expenditures would be more efficient.

“This shift is mainly driven by the energy transition, which calls for a high level of investment especially in innovative and digital assets. This leads to regulators needing a scheme that promotes the implementation of new technical and market solutions,” the report says.

In the “identifying the gap” section, the report discusses the pathway to future grids, analyzing an “announced pledges scenario” in which countries implement policies to meet their 2030 and 2050 zero-emission goals. In the announced pledges scenario, the electricity sector is a driving force in the clean energy transition and “undergoes deep transitions,” and electrical energy would grow by 20 percent per year. Elements of this scenario included the heavy deployment of EVs, more electric heating and cooling, and the development of hydrogen production using electrolysis. Wind and solar account for more than 80 percent of the total increase in global electric supply capacity over the next 20 years, an increase from the 40 percent seen in the past two decades. This scenario includes demand response—paying energy users to cut consumption in times of tight supply compared to a baseline—and energy storage. These systems will be supported by increased digitization and other modernizations on the grid.

This ambitious build-out of grids will make rapid deployment of supply chains critical, but there are significant risks to supply chains, including weather events attributed to climate change, natural disasters, a limited number of countries producing certain supplies, and surging demand for critical materials and raw materials worldwide.

In the announced pledges scenario, the total length of grids worldwide more than double between 2021 and 2050, reaching 166 million kilometers. More than 90 percent of that growth will be in the distribution grid.

The report also analyzed a net-zero emissions scenario, which it said provides a global roadmap to that goal and accelerates electricity demand growth to 3.2 percent by year by 2050, to a massive 62,000 TWh in 2050. Grid investment under the net-zero-emissions scenario passes the $1 trillion per year mark around 2035. Distribution grid investments maintain their total share of investment in both advanced economies and developing markets. Investment in emerging markets and developing economies are a majority of grid investment in both the announced pledges and net-zero emissions scenarios.

This significant investment calls for the replacement of 80 million km of transmission and distribution lines over the next two decades, which was more than the total length of all grids worldwide in 2021. More than two-thirds of the total line length by 2040 in the announced pledges scenario is yet to be built.

The report noted that failing to accelerate grid development in line with the announced pledges scenario—with “more limited investment, modernization, digitalization, and operational changes than envisioned – there would be a significant risk of stalled clean energy transitions around the world.”

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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, related companies, or clients. 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.

Concentric is pleased to welcome Mr. Steven Wishart to the team as an Assistant Vice President. 

Steve joins Concentric after spending two decades with Xcel Energy in Minneapolis and Denver, serving as Director of Resource Planning and Bidding for Northern States Power and as Director of Pricing and Regulatory Analytics for Public Service Company of Colorado. In these roles, Steve led decarbonization efforts in the upper Midwest and innovated retail rate design in Colorado.  

“I am very impressed with the leadership, knowledge, and professionalism of the Concentric team,” he stated regarding his new position. “Their expertise, collaboration, and insight provided to clients is unparalleled in the energy industry. I am privileged to join this respected team and contribute to their excellent standard of client service.” 

Steve is a leading utility economist and experienced testifying expert who has appeared in over thirty-five regulatory proceedings. His diverse experience includes demand side management, nuclear relicensing, renewable energy development, pipeline safety investments, innovative class cost allocation, time of use and dynamic rate design, economic development programs, performance-based rate making, transportation electrification, and decarbonization of natural gas utilities.  

“We are pleased to welcome Steve to Concentric,” said John J. Reed, Chairman and Chief Executive Officer of Concentric, “he brings extensive experience in decarbonization, regulatory strategy, and rate design, leveraged with industry-leading data analytics. We are excited to offer his expertise to our clients.”  

In 2023, Steve was the Chairperson of the Edison Electric Institute’s Rates & Regulatory Affairs Committee. He is a graduate of the University of Arizona with a bachelor’s degree in finance and a master’s degree in economics. He has completed the coursework for a doctoral degree in applied economics from the University of Minnesota. 

By: Concentric Staff Writer

Published: October 30, 2023

The U.S. Department of Energy (DOE) is putting billions of dollars into the development of “clean hydrogen” around the country to attract in-kind private investment, but the resource remains controversial even as state-backed regional groups prepare to launch a new era of hydrogen production with federal money.

DOE on Oct. 13 announced it awarded an unprecedented $7 billion for seven regional Clean Hydrogen Hubs to accelerate the deployment of commercial-scale hydrogen production for energy production and other uses, which the agency said is one of the largest investments in clean manufacturing and jobs in history. The initiative, funded by the 2021 Bipartisan Infrastructure Act, is meant to spur a national network of clean hydrogen production and attract a total of $50 billion in public-private partnerships.

The hubs “will kickstart a national network of clean hydrogen producers, consumers, and connective infrastructure while supporting the production, storage, delivery, and end-use of clean hydrogen,” DOE said. The new funding for the burgeoning energy resource follows the release of a hydrogen strategy and roadmap in June.

Clean hydrogen can be produced with zero or near-zero carbon dioxide emissions, and the future hubs are expected to produce 3 million metric tons of hydrogen annually, about a third of the 2030 U.S. hydrogen production target. Hydrogen is seen as a method to lower emissions from industrial sectors that are difficult to de-carbonize, which DOE said represent 30 percent of total U.S. carbon emissions.

The hubs in Appalachia, California, the Gulf Coast, the Mid-Continent, the Pacific Northwest, the Mid-Atlantic, and the Midwest (see sidebar) range in funding between $750 million and $1.2 billion apiece and target resources and industries from various regions, including renewables, natural gas, biomass and nuclear to produce hydrogen for industries such as power production, transportation and agriculture.

“Unlocking the full potential of hydrogen—a versatile fuel that can be made from almost any energy resource in virtually every part of the country—is crucial to achieving President Biden’s goal of American industry powered by American clean energy, ensuring less volatility and more affordable energy options for American families and businesses,” Secretary of Energy Jennifer Granholm said in a written statement.

One state where hydrogen production is creating controversy is California. A group known as Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) is set to develop the new hydrogen hub in that state with up to $1.2 billion in DOE funding. ARCHES is a partnership between Gov. Gavin Newsom’s Office of Business and Economic Development (GO-Biz), the University of California Office of the President, The State Building and Construction Trades Council, and Renewables 100 Policy Institute.

“These hubs will accelerate the decarbonization of hard-to-reach sectors, improve our energy security, establish good-paying green jobs, and help communities benefit from clean energy investments,” ARCHES said in comments to the Internal Revenue Service  It added that renewable clean hydrogen must be part of the state’s strategy to achieve carbon neutrality by 2045. The hydrogen development partnership said it strongly supports the development of hydrogen hubs as well the 45V tax credit for clean hydrogen production included in the 2022 Inflation Reduction Act.

ARCHES, in its comments to DOE, said that the 45V clean hydrogen tax credit will help establish a level playing field for hydrogen and other technologies. But the comments added that requirements such as mandating the location of a renewable power source to be matched with hydrogen production facilities will add costs and inhibit developers from placing renewable energy production and hydrogen production in the best locations. Hydrogen producers should also be allowed to use annual matching versus hourly tracking to have similar applicability for other technologies such as batteries, pumped hydro, compressed air and others, the comments said. Hourly tracking refers to an hourly verification of hydrogen production as meeting clean-energy standards rather than on an annual basis or other timeframe.

The University of California is a participant in ARCHES, and one signatory to the letter is Scott Brandt, Associate Vice President for Research & Innovation at the University of California Office of the President.

But faculty from the university are unhappy with that endorsement. In response to the ARCHES comments, 29 faculty members from the university wrote the Office of the President, urging it to rescind the letter. ARCHES encourages too much flexibility in the way hydrogen will be produced, and it represents California ham-stringing federal climate action rather than bolstering it, the letter says.

The 45V tax credits are the largest subsidy for clean hydrogen production in the world and are expected to deliver more than $100 billion in taxpayer dollars to hydrogen production by the mid-2040s. The lower the carbon intensity of a project the more generous the credit, but accurately determining the carbon intensity of hydrogen is difficult, the faculty letter says, and producing hydrogen from electrolysis is extremely energy-intensive, requiring large amounts of electricity. When fossil fuels are used to produce hydrogen, the carbon intensity of the resulting hydrogen can also be very high, the letter says, alleging it is too high to be an effective decarbonization tool.

“Careful policy design, including rigorous carbon accounting standards, is required to ensure that power-intensive projects like electrolytic hydrogen do not directly or indirectly expand the use of fossil-fueled electricity generation,” the faculty letter says. The letter calls for “vigorously” accounting for the source, location and time of the electricity driving the hydrogen production and says that only clean resources should be used for hydrogen production. The faculty members said the recommendations would drive carbon emissions, cause cost increases and undermine climate goals.

Additionally, on Oct. 13, a coalition of public-interest groups wrote DOE, saying it is concerned about the transparency of the hydrogen hub selection process. The groups, including Communities for a Better Environment, California Environmental Justice Alliance, Asian Pacific Environmental Network and others say they represent low-income communities that would be disproportionally affected by hydrogen production facilities.

The groups say that throughout the application development process, ARCHES has disregarded environmental justice concerns and the need for an inclusive public process. The hydrogen hubs application received no vetting from environmental justice organizations or the communities they represent, according to the letter, which urged DOE to withhold any additional funding for ARCHES until it changes course in key areas, including requiring ARCHES to eliminate non-disclosure agreement requirements that were required for organizations to have access to project details.

The groups also charge that ARCHES leadership requested signatures on a memorandum of commitment that would have indicated they support the hydrogen project. The groups said they negotiated for 10 months with ARCHES leadership to come to a solution to the requirements, leading ARCHES to issue an NDA in July that removed certain clauses and allowed signatories to share information with community members. The updated requirements would still be harmful to grassroots organizations and make them legally liable, the groups say. The environmental justice groups also requested DOE require ARCHES to amend its governance structure to maximize opportunities for impacted communities to be represented and enforce community-engagement best practices.

Separately, three U.S. Senators—Sheldon Whitehouse (D-RI), Jeff Merkley (D-OR), and Martin Heinrich (D-NM) —called on the U.S. Treasury to swiftly implement rules regarding the 45V tax credits for clean hydrogen production. “Truly clean hydrogen has enormous potential to deliver emissions reductions beyond the reach of other decarbonization technologies, but today those ambitions are undercut by a market that overwhelmingly favors dirty hydrogen.  The robustness of 45V can bridge these economics until our decarbonized grid can support a competitive clean hydrogen industry,” the senators said in the letter.

Many dynamics are swirling around hydrogen technology and its implementation in the U.S., along with many differing opinions. But there is no doubt this elemental technology is enjoying strong support at federal, state, and business levels.

Additional Information

The seven hubs to receive $7 billion in federal funds include:

Appalachian Hydrogen Hub (up to $925 million): Known as the Appalachian Regional Clean Hydrogen Hub, it is a joint project between West Virginia, Ohio, and Pennsylvania and is a project to use natural gas to create low-cost hydrogen and permanently store the carbon emissions through a series of hydrogen pipelines, multiple hydrogen fueling stations and CO2 storage facilities. It is expected to bring jobs to coal communities, including 18,000 construction jobs and 3,000 permanent jobs.

California Hydrogen Hub (up to $1.2 billion): A project of the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) made from renewable energy and biomass and will provide a blueprint for decarbonizing public transportation, heavy-duty trucking and port operations, which are primary drivers of emissions and air pollution in the state. The hub has committed to requiring Project Labor Agreements– — for all projects connected to the hub and is expected to create 130,00 construction jobs and 90,000 permanent jobs.

Gulf Coast Hydrogen Hub (up to $1.2 billion) The HyVelocity hub in Texas will be near Houston and will include large-scale hydrogen production using both natural gas with carbon capture and renewables-powered electrolysis in an effort to lower the cost of hydrogen production.

Heartland Hydrogen Hub (up to $925 million) An initiative between Minnesota, North Dakota, and South Dakota, the hub aims to decarbonize fertilizer production in the agriculture industry, decrease the cost of regional hydrogen, and advance the usage of hydrogen for power production and cold climate space heating. The hub will offer equity ownership opportunities to tribal communities, local farmers, and farmer cooperatives through a private-sector partnership that will lower the prices of clean fertilizer for farmers.

Mid-Atlantic Hydrogen Hub (up to $750 million): A partnership between Pennsylvania, Delaware, and New Jersey, the hub will explore hydrogen-driven decarbonization using historic oil infrastructure and existing right-of-ways. It will develop renewable hydrogen facilities from renewables and nuclear power using both established and more innovative electrolyzer technologies. The hub plans to negotiate project labor agreements and provide close to $14 million for regional workforce development boards to develop community college training and pre-apprenticeships. It is expected to create 14,4000 construction jobs and 6,400 permanent jobs.

Midwest Hydrogen Hub (up to $1 billion): The Midwest Alliance for Clean Hydrogen is a partnership between Illinois, Indiana, and Michigan that will enable decarbonization through using hydrogen for steel and glass production, power generation, refining, heavy-duty transportation using renewable energy, natural gas, and nuclear energy.

Pacific Northwest Hydrogen Hub (up to $1 billion): The hub is a project between Washington, Oregon, and Montana and plans to use renewable resources to produce hydrogen through electrolysis, aimed at reducing the cost of electrolysis, making the technology more widespread, and reducing the cost of hydrogen production. It has committed to inking Project Labor Agreements for all projects of more than $1 million and investing in joint labor-management/state-registered apprenticeship programs. It is expected to create 8,050 construction jobs and 350 permanent jobs.

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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, related companies, or clients. 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.

Concentric is proud to announce a number of strategic leadership transitions effective January 1, 2024. These strategic changes position Concentric to continue to expand its industry-leading service offerings.

Danielle Powers, currently an Executive Vice President, will be promoted to the role of Chief Executive Officer. Ms. Powers has over 30 years of experience in the industry and has been a leader in Concentric’s consulting practice since 2005.

“The questions around the energy transition are now harder to solve, and the answers are becoming more nuanced,” said Ms. Powers of the new appointment, “as the energy industry changes and Concentric evolves, our commitment to providing excellent service will not change.” Ms. Powers will be responsible for Concentric’s corporate growth strategy and internal operations and will continue to serve clients as an expert in resource planning and the wholesale electricity market.

Focusing on client satisfaction, service offerings and delivery, and corporate communications, Daniel Dane, currently an Executive Vice President, will be promoted to become Concentric’s new President and Vice-Chair. Mr. Dane is entering his 20^th year at Concentric, and in addition to his role as a senior leader in Concentric, Mr. Dane plays a principal role in Concentric’s financial advisory and regulatory practices.

Mr. Dane shared, “I look forward to continuing to collaborate with our exceptional clients and employees to ensure Concentric remains the premiere North American energy industry advisory firm. Our clients are the heart of our business, and we will enhance and create new service offerings to meet their needs and expectations as the energy industry evolves.” Mr. Dane will also continue to assist clients as an expert witness on utility regulation and financial advisory matters.

John J. Reed, Concentric’s current Chairman and Chief Executive Officer, will continue as the firm’s Chairman. Mr. Reed will continue to actively advise clients and lead Concentric’s Board of Directors.

“The Board of Directors were thoughtful and deliberate in their consideration of these appointments and unanimously and enthusiastically endorse these leadership changes,” said Mr. Reed, “Dan and Danielle represent vibrant new leadership steeped in Concentric’s traditions and values. This leadership progression allows Concentric to expand, grow, and deepen the exceptional talent and services we offer the energy industry as it navigates new circumstances, energy demands, and customer preferences.”

Published: September 27, 2023

By: Concentric Staff Writer

Federal energy regulators’ reform of a 1978 federal law intended to spur renewable energy was correct, according to a recent U.S. Court of Appeals ruling, but more environmental review will be required.

The legal battle that led to the Sept. 5 ruling by a U.S. Appeals Court regarding PURPA reform is intertwined with another ongoing proceeding. That is because the Sept. 5 ruling involves the longstanding “Chevron doctrine,” which is subject to a separate challenge at the U.S. Supreme Court.

Regarding the Sept. 5 ruling by the U.S. Court of Appeals for the Ninth Circuit, the three-judge panel found that the Federal Energy Regulatory Commission (FERC) in its 2020 interpreted the Public Utility Regulatory Policies Act (PURPA) correctly in its reform of that law. But the court also found that FERC violated the National Environmental Policy Act (NEPA) when approving Order 872, sending that aspect of the ruling back to the federal agency.

Plaintiffs, including the Solar Energy Industries Association (SEIA) and environmental organizations, had challenged FERC’s Order 872 (RM19-15, AD16-16) on the basis that FERC did not issue an environmental assessment (EA) as required by NEPA. The court found that the “more substantive” elements of Order 872 fall outside a legal exception to NEPA regarding rules that do not substantially change those being amended. But the court, in its decision, also rejected arguments by FERC that there are no reasonably seen foreseeable impacts on the environment from Order 872.

The judges said the appropriate remedy was to remand FERC’s NEPA violation back to the agency without vacating the rule, an action known in legal terms as “vacatur.”

“Although FERC’s failure to prepare an EA is a serious violation, Order 872 does not suffer from fundamental flaws making it unlikely that FERC could adopt the same rule on remand, and the disruptive consequences of vacatur would be significant,” the court said.

PURPA, enacted in response to the energy crisis of the 1970s, was intended to encourage the development of power plants built by non-utility-owned energy producers, which were known as “qualifying facilities” (QFs). Generally, electric utilities not in organized wholesale markets in independent system operators and regional transmission organizations must buy power from qualifying facilities under 80-MW capacity, at rates established by FERC.

The judges in the U.S Court of Appeals decision rejected arguments by the petitioners that FERC’s Order 872 is inconsistent with directives in PURPA that FERC encourage the development of QFs. PURPA, on its face, gives FERC broad discretion to evaluate which rules are necessary to encourage QFs and which are not, the opinion by Judge Eric D. Miller states, one of three judges on the panel. FERC’s ruling was therefore not unjust and unreasonable, the order says.

The judges in the ruling rejected four challenges by the petitioners of Order 872, holding that the “modified site rule,” which determines whether neighboring facilities are counted as one or two facilities in terms of QF interpretation, survives something known as the Chevron doctrine.

The judges also ruled that a provision known as the Fixed-Rate Rule, which modified the rates paid to QFs, also survives Chevron and is not arbitrary or capricious under the Administrative Procedures Act (APA). Finally, the panel found that the provision allowing states to adopt a rebuttable presumption that, for utilities in certain organized energy markets, the locational market price represents the purchasing utility’s avoided costs,¹ is not arbitrary or capricious under the APA.

Judge Patrick J. Bumatay concurred and dissented in part with the order denying FERC’s enactment of the revised rules. However, Bumatay based his opinion on the text of PURPA instead of the Chevron deference. He also said that the environmental groups lacked standing to bring the case because they didn’t allege that they will suffer environmental harm in a way that is sufficient to confer NEPA standing.

The 2020 rule approved by FERC put in place the rule for facilities within one mile of each other but adopted a new approach for facilities more than one mile apart. The new rule creates an irrebuttable presumption that facilities more than 10 miles apart are at separate sites.

Petitioners argue that Order 872’s definition of “at the same site” defied the plain meaning of the statutory text, saying the term “site” is clear and unambiguous. The petitioners had argued that developers skirted the 80-MW requirement for QF standing by splitting projects up.

Separately, the Edison Electric Institute (EEI) and NorthWestern Energy recently petitioned the U.S. Supreme Court to reverse a U.S. Court of Appeals for the District of Columbia decision regarding the Chevron doctrine. The Chevron doctrine  says that courts should generally defer to interpretations by agencies of judicial statutes that are viewed as began within a grey area.

The petition asks the Supreme Court to reverse a ruling by FERC that interpreted PURPA in a way that required a utility to purchase power from a Montana solar project. The project was a 160-megawatt (MW) capacity but can only deliver 80 MW to the grid, so FERC designated it as a QF. An appeals court upheld FERC’s interpretation, citing the Chevron doctrine.

The legal question in that case is whether “power production capacity” in PURPA refers to a facility’s maximum net output to the grid at one time, or the maximum amount of energy the facility can create. A second legal question outlined in the document is whether the Supreme Court should reconsider how and when Chevron should apply, or “or at least clarify that courts must exhaust normal statutory-interpretation tools before concluding that a statute is ‘ambiguous’ at Chevron step one.”

The developer of the Montana solar project, Broadview Solar, intends to artificially limit the plant’s output to no more than 80 MW, apparently to meet requirements for QF status and have a guaranteed buyer for the output.

FERC “flip-flopped” on the issue, finally ruling that the term “power production capacity” in PURPA refers to the maximum amount of power that the project can deliver to the grid, the document says.

“The D.C. Circuit upheld the agency’s orders on the ground that FERC’s reading of PURPA is entitled to Chevron deference. But the D.C. Circuit’s application of Chevron was wrong from beginning to end,” the petition by EEI, a trade association representing investor-owned utilities, and Northwestern says.

If Chevron is understood to condone the result in the case, it is further evidence that the Chevron doctrine should be reconsidered, or its limits clarified, the petition says.

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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.

1 Avoided costs is a figure referring to the cost the utility avoids by not generating the power itself.

Published: August 30, 2023

By: Concentric Staff Writer

The U.S. Department of Energy (DOE) is making $30 million available to increase domestic sourcing of critical minerals from coal-based resources used in clean energy and transportation technologies.

The funding (DE-FOA-0002619), allocated in the 2021 Infrastructure Investment and Jobs Act and announced Aug. 21, is to meet the need for critical minerals used in the production of solar panels, wind turbines, electric vehicles, and hydrogen fuel cells, DOE said in a news release. The goal is to lower the cost of these technologies, meet growing demand, and reduce dependence on offshore supplies, DOE said.

“President Biden’s Investing in America agenda is helping rebuild America’s manufacturing sector by enhancing our ability to produce the critical minerals necessary to develop clean energy technologies,” Energy Secretary Jennifer M. Granholm said in a written statement. “Thanks to these transformative investments, we are reducing our reliance on foreign supply chains while delivering high-quality jobs throughout the communities that have helped power the nation for generations.”

The U.S. currently imports more than 80 percent of such minerals from non-domestic suppliers, DOE said. In 2022, the U.S. imported more than half of its consumption of 43 of the 50 critical minerals identified by the U.S. Geological Survey and there was no domestic production of 14 critical minerals, DOE said.

The funding will be used to conduct proof-of-concept testing in laboratory or bench-scale facilities to research “economically viable, environmentally benign extraction, separation, and refining technologies.” Such minerals are used in clean energy, national defense, and commercial commodity products and equipment.

The funding opportunity is divided into two topic areas: advanced process development for production of rare earth metals and co-production of critical minerals and materials from coal-based resources; and production of critical minerals and materials, excluding rare earth minerals, from coal-based resources.

There is potential for advanced processes to produce individually separated, high-purity rare earth oxides and salts and high-purity single or binary rare earth metals at costs about 20 percent lower than currently available conventional separation and conversion technologies, the agency said. The materials will be produced in small-scale pilot facilities that extract and separate critical minerals from coal-based resources.

The Infrastructure Investment and Jobs Act authorized appropriations to develop and assess advanced separation technologies for the extraction and recovery of rare earth elements and other critical minerals from coal and coal by-products and determine if there are any environmental or public health impacts from the recovery of these resources.

One goal of the program and other DOE-related activities is to help build a domestic supply chain of rare earth elements from a diverse list of resources and establish private investments to create the first domestic midstream processing capabilities for these resources in decades. The supply chain consists of mining, separation, refining, alloying, and manufacturing devices and components parts, DOE said. Forming such a supply chain is essential for domestic self-reliance in this area, the agency said.

Responses to the funding opportunity are due Oct. 20 Eastern Time, DOE said.

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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: August 24, 2023

By Concentric Staff Writer

Grid operators across the U.S. are expressing concern over new power plant regulations proposed by the U.S. Environmental Protection Agency (EPA), saying they could lead to reliability problems and that they rely on technologies that are not yet commercially viable.

EPA’s proposed rule (EPA-HQ-OAR-2023-0072-0001) issued in May would strengthen the current New Source Performance Standards for stationary power plants—mainly those powered with natural gas. It would also establish emissions standards for plants that would limit carbon dioxide emissions, including plants fueled by coal, oil, and natural gas, as well as establish emission guidelines for large, frequently used stationary combustion turbines, generally powered by natural gas.

EPA , when issuing the rule, said it could achieve up to 407 million metric tons of CO2 emission reductions. As it finalizes the rule it will adopt additional advanced modeling, aligning methodologies and “considering real-world scenarios within the power sector to best understand how components of the rule impact each other,” the agency said.

Nearly 1,200 comments were filed on the proposed rule, including a joint filing by four major independent system operators (ISO) and regional transmission organizations (RTO). The comments by Electric Reliability Council of Texas, the Midcontinent Independent System Operator, PJM Interconnection, and Southwest Power Pool expressed concern over the impact of the rule on reliability and its reliance that new carbon-capture and sequestration (CCS) and hydrogen technologies will be available in time, saying “hope is not an acceptable strategy.”

“The Joint ISOs/RTOs are concerned that the substance of the Proposed Rule as presently configured, as well as its timing, have the potential to materially and adversely impact electric reliability,” the filing says. “Moreover, the Proposed Rule, when combined with other EPA rules and other policy actions, could well exacerbate the disturbing trend and growing risk wherein the pace of retirements of generation with attributes needed to ensure grid reliability is rapidly exceeding the commercialization of new resources capable of providing those reliability attributes.”

The ISOs and RTOs said they have been at the forefront of issues created by renewables integration and increasing retirements of dispatchable generation units that will be exacerbated by the proposed rule. EPA is trying to design the rule to avoid a wave of generation retirements, but the agency assumes that new technologies will be available and able to substitute for current technologies, they said. The rule would also have short-term impacts by having a chilling effect on the investments needed to maintain system reliability as the new technologies are developed. Retirements of generators are already being seen because investors are reluctant to keep capital-intensive resources operational, the filing says.

The ISOs and RTOs urged EPA to address their reliability concerns, shortcomings in the agency’s analysis and assumptions, and that there is a need to incorporate timely reviews of technology advancement and unit retirements into the rule. They suggested building into the rule a process to monitor retirements and the development of CCS and hydrogen technologies. They also suggested EPA update the definition of “system emergency” to reduce uncertainty around when a unit might be called upon for reliability. EPA projects that the new technologies will prove to be economic as a result of subsidies built into the Inflation Reduction Act, but those technologies are not yet feasible on a large scale, and there are reasons to be skeptical they will be within the compliance period, the grid operators said.

The California Independent System Operator in a separate filing  told EPA that it supports the proposal, including provisions that would address situations where units are required to run for reliability purposes. These include EPA’s creation of sub-categories of resources for purposes of complying with the best system of emission reduction and establishment of lead-times for those resources to comply. EPA said it will also consult with the U.S. Department of Energy and Federal Energy Regulatory Commission during implementation and permit state implementation plans to include averaging and emission trading to meet compliance, provided that states ensure an overall level of emission performance by the affected electric generating units that is equivalent to each source individually achieving its own standard of performance.

EPA should also consider establishing additional pathways in any final rule to allow resources to operate on a temporary basis notwithstanding compliance schedules, if needed to support electric grid reliability, CAISO said. These include a process “to authorize specific resources to operate for a limited time based on a showing of reliability need or allowing states to demonstrate in their implementation plans that a temporary electric reliability need outweighs achieving emission reductions at specific facilities based on the best system of emission reduction when considering other steps and mitigation taken to reduce emissions within the state, air districts, and local communities.”

ISO New England in its comments said that based on its analysis, the rulemaking would have limited impact on oil and natural gas boilers, and they would mostly impact natural gas-fired units larger than 300 MW operating at greater than 50 percent of capacity factor. This might cause an operational shift from larger generators to smaller, less-efficient units, the ISO said, and the larger units also might have an incentive to avoid the energy market if compliance costs exceed potential profits. Generators operating far from the 50-percent capacity factor would have weaker incentives, which could cause market imbalances.

The ISO also said its analysis shows that with all the coal units scheduled to retire by 2032 and less generation from larger regulated gas units, the rule must be implemented carefully. The grid operator said it is concerned that it relies on coal, oil, and gas units at certain times when renewables are not available, and the rules could encourage retirement of those units.

“The ISO is aware that EPA plans to publish a separate rulemaking so as to cover all of the existing natural gas fleet. It is important to note that, until all parts of the rule are published, it is difficult for the ISO to gauge the overall impact of this current proposed rule and the results of this analysis may be underestimating the impact of the rule on future grid reliability,” the filing says. 

EPA’s proposed standards are based on a level of emission reductions that can be achieved through CCA as well as conversion of plants to burn hydrogen, but there are technical and economic hurdles to deploying these technologies under the proposed timelines. Those technologies might not be viable in New England, which does not have the capacity to store large amounts of CO2, it said.

“The lack of geological storage sites in New England also makes it infeasible to implement low-GHG hydrogen co-firing at large scale,” ISO-NE said. There are also gaps between ISO nameplate values and EPA-based historically derived values that create gaps in analysis that could greatly affect implementation of the rule, the grid operator said.

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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: July 25, 2023

By: Concentric Staff Writer

Developers of the Mountain Valley Pipeline took their battle over the project to the U.S. Supreme Court, asking it to overturn a lower court ruling that shut down construction as it neared completion.

Mountain Valley Pipeline LLC (MVP) in its July 14 application asked the high court to vacate two “extraordinary stay orders” issued by the U.S. Court of Appeals for the Fourth Circuit that are currently blocking the proposed 303-mile natural gas pipeline that would interconnect with existing pipelines in the Southeast and Mid-Atlantic. The project has been embroiled in litigation over the past six years, the target of dozens of lawsuits in the Fourth Circuit that have challenged “virtually every federal authorization issued for the project,” the application states. (23A35).

The project was bolstered when Sen. Joe Manchin (D-West Virginia) conditioned his approval of the Inflation Reduction Act on the easing of regulatory barriers to its construction. It is mostly completed, with only 3.5 miles left to be constructed in the Jefferson National Forest, including some stream crossings outside the forest and some reclamation activities. Manchin eventually withdrew legislation that would have required the Federal Energy Regulatory Commission (FERC) to take all necessary actions to ensure its completion. The Fiscal Responsibility Act (FRA), which President Joe Biden signed on June 3, required that all federal permits for the project to be issued by June 24. More than 4,400 acres of trees have been cleared and only 3.39 acres of clearing are still needed.

The U.S. House of Representatives on July 20 filed a brief amicus curiae with the Court in support of the application to vacate, stating that Congress has the authority to change law as it sees fit.

“The Respondents do not suggest that Congress lacks the general authority to pass legislation related to pipelines or to change existing statutes. They instead suggest that something nefarious is afoot because the FRA applies to a single pipeline project. But Congress may legislate as broadly or narrowly as it sees fit, and—as this Court has recognized—it may pass targeted legislation that applies only to a single subject,” the brief states.

The developer in recent months received necessary authorizations from the U.S. Forest Service, the Bureau of Land Management (BLM), the U.S. Fish and Wildlife Service, and others. On June 28, FERC authorized general construction to resume, but work was halted by the previous stay orders. The Fourth Circuit issued orders blocking construction while it adjudicates petitions for review of the Forest Service and BLM authorizations.

The developer said the most recent stay orders, however, are “critically different” because they came after Biden’s signing of the Fiscal Responsibility Act. Congress in the legislation found that the project is in the national interest, that it will serve demonstrated gas demand in the Northeast, Mid-Atlantic, and Southeast, would increase gas reliability of the gas supply at reasonable prices, will allow natural gas producers to access additional markets and reduce carbon emissions and facilitate the energy transition, the application says.

“The court of appeals thus had no authority to issue the stay orders that MVP challenges in this application,” the application says. “Section 324 [of the law] unambiguously removes jurisdiction from all courts, including the Fourth Circuit, to determine whether the Forest Service and BLM authorizations for work in the Jefferson National Forest, and the Biological Opinion and Incidental Take Statement of the Fish and Wildlife Service, are lawful.” The developer asked the court to vacate the orders and underlying petitions for review to be dismissed as soon as possible, and in any event, by July 26.

Mountain Valley Pipeline LLC said the court of appeals lacks jurisdiction in the case and that even if it did, Congress has ratified the agency actions and superseded any provisions of the law that could serve as a basis for relief. Congress has issued a “command” for the project to be finished and it must proceed without further delay, the application to vacate states.

The State of West Virginia on July 24 also filed in support of MVP.

“Congress was right that the Pipeline’s benefits make finishing it a national priority. West Virginian jobs and tax revenues are on the line. The Pipeline will also bring essential additional natural gas supply to help meet the region’s growing needs at reasonable prices. And it will help insulate our energy sector as a whole from foreign supply challenges and domestic cyberattacks. Especially with no plausible legal justification to withhold these gains, the Court should vacate the stays,” the document states.

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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: July 20, 2023

By: Concentric Staff Writer 

Officials of the Canadian province of Ontario said they are launching a new energy initiative to address growing electricity demand due to electrification using a variety of resources, reflecting electrification trends also occurring across the United States. 

Energy Minister Todd Smith announced the plan on July 10, saying strong economic growth and trends such as electric vehicles create a need for new zero-emissions electricity generation, long-duration energy storage and new transmission infrastructure. 

“Our government’s open for business approach has resulted in unprecedented investments and job creation, from electric vehicles and battery manufacturing to critical minerals to green steel,” Smith said in written statement. “Powering Ontario’s Growth lays out the province’s plan to build the clean electricity generation, storage, and transmission we need to power the next major international investment, the new homes we are building, and industries as they grow and electrify.” 

New EV and battery manufacturing facilities from companies such as Stellantis, Volkswagen and Umicore are contributing to a rise in electricity demand in Ontario for the first time since 2005. Smith said the province is working with the steel industry to end usage of coal and to electrify operations to produce “green steel” in the cities of Hamilton and Sault Ste. Marie. The investments alone will increase electricity demand by eight terawatt hours, doubling the annual average energy use of the Ottawa region.  

The province’s Independent Electricity System Operator (IESO) has recommended an early start to meet energy demands through 2030 while keeping costs low. The IESO’s Pathways to Decarbonization Report issued in December 2022 included one scenario for demand growth that could rise from 42,000 MW today to 88,000 MW by 2050. 

Powering Ontario’s Growth includes a nuclear energy component, such as a plan to site 4,800 megawatts (MW) of new nuclear on the current site of the Bruce Power Nuclear Generating Station, already the largest operating nuclear plant in the world with 6,550 MW of capacity. Nuclear power currently provides about 50 percent of the province’s energy supply, and it is one of the cleanest grids in the world, officials said. 

A second aspect of the new plan is competitive procurements of new clean-energy resources such as wind, solar, hydroelectric, batteries and biogas, while a third component calls for designating and prioritizing three new electric transmission lines: one to power Algoma Steel and other companies in Northeastern Ontario, one line in the Ottawa region and one across Eastern Ontario. The Energy Minister’s office said it would direct the IESO to conduct a report on transmission options to address system bottlenecks between Toronto, Northern Ontario, and into downtown Toronto, where growth is expected. 

The province will also request Ontario Power Generation to optimize hydroelectric generation sites and assess proposed pumped storage projects in Marmora and Meaford to “improve grid efficiency.” 

The new plan also aims to keep costs low by starting to plan for the future of energy efficiency programming to reduce demand and support the deployment of distributed energy resources such as rooftop solar and EV batteries.  

“As our province moves toward an electric future with a strong end-to-end EV supply chain, there has never been a greater need for clean, affordable energy that companies can rely on. This plan brings us one step closer to being a world-leading energy powerhouse,” Ontario Minister of Economic Development Vic Fedeli said in a written statement, adding that the province has attracted billions of dollars in investment from domestic and international companies over the past 2 ½ years. 

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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.