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. 

Published: July 17, 2023 

By: Concentric Staff Writer 

Global trading in liquefied natural gas (LNG) continues to rise, setting a new record in 2022 as European and Asian import dynamics changed due to the war in Ukraine and other factors came into play in other regions. 

The new record in global LNG trade in 2022 was driven by a 5 percent rise in trade over the year before, with increases in LNG capacity occurring particularly in the U.S., the U.S. Energy Information Administration (EIA) said in its July 5 Today in Energy report. Global trade in LNG averaged 51.7 billion cubic feet per day (Bcf/d) in 2022, according to the EIA, using data compiled by France-based CEDIGAZ, the international association for natural gas. European demand contributed to the trade growth as the region moved away from Russian gas imports. 

Export Activity 

LNG exports from the U.S. rose 16 percent in 2022 from the previous year, rising 1.4 Bcf/d to 10.2 Bcf/d. Facilities such as the new Calcasieu Pass export project in Cameron Parish, Louisiana, the seventh new such facility producing LNG since 2016, helped the U.S. become the top LNG exporter in the first half of 2022, EIA said.  

However, in the second half of 2022, the Freeport LNG export terminal on the Gulf Coast in Texas shut down due to a fire, reducing its export capacity by about 2 Bcf/d. Qatar (10.5 Bcf/d) and Australia (10.4 Bcf/d) then took over as the top exporters for the year last year.  

In 2022 LNG exports increased by a combined 1.3 Bcf/d from Malaysia, Trinidad and Tobago, Russia, Oman, and Equatorial Guinea, according to the report. Disruptions in domestic natural gas production caused a combined LNG export reduction of 1.5 Bcf/d from Algeria and Nigeria. 

Import Activity 

Turkey had the largest increase in imports out of all countries in 2022, with a 65 percent increase equivalent to 6.5 Bcf/d compared to the previous year. Asian imports declined by 9 percent, and imports to Latin America declined by 34 percent. Imports into EU-27 countries increased by a high amount, EIA said, rising by 73 percent as the region moved away from Russian supply. About 85 percent of that import increase came from France, the U.K., Spain, the Netherlands, and Belgium. 

In Asia, China surpassed Japan as the top importer in 2021, a position Japan had held for 50 years, but Japan reclaimed the top spot in 2022. China’s zero-Covid policies, increased pipeline imports from Russia, and increased coal usage drove that change. Record-high LNG prices on the spot market led Asian countries to reduce spot market purchases and led to an 18 percent decline in imports into India, Pakistan, and Bangladesh in 2022, EIA said. 

Brazil had the highest decrease in LNG imports among Latin American countries in 2022, rising by 70 percent (.6 Bcf/d), as higher hydroelectric power plant output displaced natural gas. 

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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 6, 2023

By: Concentric Staff Writer

Texas Governor Greg Abbott signed new legislation reforming the state’s utilities and allocating reliability costs to intermittent generation sources in the same week a searing heat wave set in and set electricity prices skyward.

Governor Abbott on June 9 signed HB 1500, a “sunset” bill, which is a regular reauthorization of the Public Utility Commission of Texas (PUCT), and includes several provisions to shore up grid reliability. The bill drew a negative reaction from some renewable energy interests over provisions they say are aimed at hindering clean-energy resources.

Reliability has become more of a discussion topic in Texas since February 2021 when Winter Storm Uri caused widespread outages and hundreds of deaths, mostly due to freeze-ups of natural gas infrastructure. Summer reliability risks include grid impacts due to high electricity load and hot weather—the Electric Reliability Council of Texas (ERCOT) issued a voluntary conservation call on June 20 from 4 p.m. to 8 p.m. central time that followed a “weather watch” from June 15–21.

The HB 1500 legislation requires generation resources, other than battery storage facilities, to demonstrate to the PUCT that they will be available to operate when called upon during times of highest reliability risk. The owner or operator must be able to meet the requirement by January 1, 2027, by supplementing or contracting with on-site or off-site resources, including energy storage. The legislation directs the PUCT to determine the average capability based on “expected resource availability” and seasonal-related capacity on a standalone basis.

HB 1500 also requires establishing an ancillary services program to procure energy for dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. It also requires a determination of the quantity of services necessary based on historical variations in generation availability for each season, based on a targeted reliability standard or goal. This includes the intermittency of non-dispatchable generation facilities—wind and solar—and forced outage rates for dispatchable generation facilities.

Under the new law, the PUCT cannot require any retail customer or load-serving entity in the ERCOT power region to purchase credits designed to support a required reserve margin or other capacity or reliability requirement unless the PUCT ensures that the net cost of the credits to the ERCOT market does not exceed $1 billion annually, less the cost of any interim or bridge solutions. The credits are available only for dispatchable generation and the credits must be obtained centrally to prevent market manipulation. A generator also cannot receive credits that exceed the amount of its generation bid into the forward market.

Generation units can receive a credit only for being able to perform in real-time during the tightest intervals of low supply and high demand on the grid, to be defined annually by the PUCT. The bill also establishes a penalty for generators that bid into the forward market but do not meet their assumed obligation. The bill also establishes a single ERCOT-wide clearing price for the credits program that does not differentiate payments or credit values based on locational constraints.

A new Grid Reliability Legislative Oversight Committee was also created through the new law, which will oversee the PUCT’s implementation of legislation related to the regulation of the Texas electricity market enacted by the 87^th and 88^th Legislatures. The eight-member committee will be composed of three members from the Senate, three from the House, and the Senate and House chairs having “primary jurisdiction over matters relating to the generation of electricity.”

The legislation requires the PUCT to file a report no later than December 1 each year that includes the annual costs incurred by load-serving entities that back up dispatchable and non-dispatchable generation resources to guarantee that a firm amount of electric energy will be available to the Texas power grid.

Following a review of the report, the PUCT will determine whether specific transmission or distribution system constraints or bottlenecks in Texas give rise to market power in specific geographic markets. If there is a finding that such constraints give rise to market power, the PUCT can order reasonable mitigation by requiring utilities and others to construct additional transmission or distribution capacity or both.

Environment Texas Executive Director Luke Metzger issued a statement in opposition to the passage of HB 1500, saying it favors fossil-fuel-powered generators and will lead to higher transmission costs for renewables.

“We need, and Texans want, more clean energy, not less,” Metzger said. “There is strong support for more wind and solar energy, more battery storage, more energy efficiency, and more interconnection with the national grid. Unfortunately, the Legislature ignored these solutions to strengthen our electric grid while protecting consumers and the environment.”

However, Brent Bennett, policy director with the Texas Public Policy Foundation, lauded passage of the bill.

“We commend the legislature for passing HB 1500, which renews the Public Utility Commission on the condition that they take up needed market reforms, including Governor Abbott’s 2021 directive to ‘allocate reliability costs to generation resources that cannot guarantee their availability,’ and to ‘ensure that all power generators can provide a minimum amount of power at any given time.’ These reforms are critical in light of the federal government’s profligate spending on unreliable energy sources and onslaught of regulations on reliable energy sources,” Bennett said.

The new legislation coincided with a heat dome that hit the state in recent weeks, which will increase electricity demand for air-conditioning. Early in the week of June 25, Texas was under a hazardous heat warning, with afternoon temperatures of 104 degrees Fahrenheit recorded on June 27.

ERCOT broke its peak demand record on June 19 at 79,304 MW surpassing the previous June’s record of 76,718 MW. ERCOT set 11 peak demand records in the summer of 2022, typically in the late afternoon and evening hours. The grid operator said it was using tools such as reserve power, calling for large customers to reduce usage and bringing more generation online sooner. ERCOT said that other than extreme heat and record demand, it was experiencing outages of thermal power plants, declines in solar in the evening hours and low performance from wind during the summer peak.

The conditions on the grid led to extreme wholesale market prices in excess of $5,000 per MWh[1] on June 20.

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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.

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[1]“ERCOT: Real-Time Price – LCG Consulting.” EnergyOnline, www.energyonline.com/Data/GenericData.aspx?DataId=4. Accessed 29 June 2023.

June 9, 2023–Concentric today announced the appointment of Jeff McDonald, Ph.D. as a Vice President.

Dr. McDonald has over 20 years of experience in the economics of wholesale electricity markets and is an expert in market design, performance, and monitoring. Dr. McDonald is also a testifying expert on wholesale electric market design, just compensation for generator assets, market competitiveness, and cost allocation.

“We are excited to welcome Jeff to Concentric and share his expertise with our clients,” said Danielle Powers, Executive Vice President at Concentric. “The wholesale electric markets are experiencing significant issues from reliability challenges caused by extreme weather conditions to a changing resource mix to resource adequacy concerns. Jeff’s experience will be critical to our clients as they navigate these dynamic factors and articulate their decisions to stakeholders.”

Before joining Concentric, Dr. McDonald was a Principal at Libertas Market Analytics, where he provided a wide range of analytical services to clients in the wholesale electricity industry. Prior to that position, he held various roles in Market Monitoring with the California Independent System Operator and headed the Market Monitoring department at ISO New England. In these roles, he provided extensive expert witness support in regulatory proceedings, stakeholder engagement, and technical consultations on Independent System Operator market rules, performance, and practices.