Concentric Energy Advisors

Key takeaways:

President Donald Trump issued a series of executive orders aimed at bolstering the U.S. domestic coal industry.

Among these efforts are boosting the mining of coal, using it more for the generation of electricity, and increasing exports.

Many of Trump’s orders involve unraveling the priorities of former President Joe Biden regarding fossil fuels.

Trump is realigning the priorities of federal energy agencies to promote more usage of coal, drawing fire from environmental groups.

President Donald Trump is set on revitalizing the nation’s coal industry, issuing a series of executive orders to stimulate coal mining, increase coal exports, and encourage usage of the resource to power artificial intelligence, and other sources of rising demand for electricity.

Among the efforts is Trump’s April 8 executive order dubbed “Reinvigorating America’s Beautiful Clean Coal Industry and Amending Executive Order 14241,” which strives to accelerate coal mining on federal lands and undertake other actions to bolster the industry. The actions drew fire from environmental groups such as the Sierra Club.

“It is the policy of the United States that coal is essential to our national and economic security,” the White House said on its website when announcing the order. “It is a national priority to support the domestic coal industry by removing Federal regulatory barriers that undermine coal production, encouraging the utilization of coal to meet growing domestic energy demands, increasing American coal exports, and ensuring that Federal policy does not discriminate against coal production or coal-fired electricity generation.”

The order directs the chair of Trump’s National Energy Dominance Council (NEDC), Secretary of the Interior, Doug Burgum, to designate coal as a mineral that entitles it to the benefits of a separate executive order under Trump that is intended to increase mineral production.

The order also directs Interior Secretary Burgum, Secretary of Agriculture Brooke Rollins, and Secretary of Energy Lee Zeldin to submit a joint report to the president that identifies coal resources on federal lands, assesses impediments to mining coal, and proposes policies to address those impediments. The Energy Secretary was also directed to analyze the impact that the availability of that coal could have on electricity costs and grid reliability.

The order says the Secretaries of State, Commerce, and Energy, and other officials involved with financing energy projects should review “their charters, regulations, guidance, policies, international agreements, analytical models and internal bureaucratic processes” to ensure they don’t discourage financing of coal mining and use of coal in electricity generation projects.

The Secretary of State, the Secretary of Commerce, and other officials are also to take all actions necessary to identify and promote opportunities for coal and coal technologies, as well as facilitate international offtake agreements for United States coal.

Other directives in the order are expanding the usage of categorical exclusions that could further the production and export of coal; exploring whether coal used in the production of steel meets the definition of a “critical material” under the Energy Act of 2020, and if so, placing it on the critical materials list.

In the area of powering artificial intelligence data centers, the Secretary of the Interior, the Secretary of Commerce, and the Secretary of Energy are to identify regions where coal-powered infrastructure is available and suitable for powering data centers and high-performance computing operations and submit a report to the NEDC.

Trump’s order, following his public pronouncements that clean-coal technology should be developed, directs the Secretary of Energy to accelerate the development of such technologies “including technologies that utilize coal and coal byproducts such as building materials, battery materials, carbon fiber, synthetic graphite, and printing materials, as well as updating coal feedstock for power generation and steelmaking.”

Trump in another April 8 executive order, “Regulatory Relief for Certain Stationary Sources to Promote American Energy,” granted nearly 70 coal-fired power plants an extension to comply with regulations restricting emissions of chemicals such as mercury, arsenic, and benzene.

Under Trump, the U.S. Environmental Protection Agency had previously signaled it would grant the two-year exemptions to the Mercury and Air Toxic Standard (MATS), a Biden-era regulation that drew lawsuits from 23 states. Compliance with the rule would cost the coal industry about $790 million in the decade beginning in 2028, including at least $92 million for the power sector, according to EPA.

“President Trump is delivering on the mandate Americans gave him last November by empowering different forms of domestic energy to drive down costs, increase domestic energy supply, and improve our grid security as we pioneer the path to become the Artificial Intelligence capital of the world,” EPA Administrator Lee Zeldin said in a written statement.

The current MATS rule has caused “significant regulatory uncertainty,” especially for coal plants in Florida, Illinois, Kentucky, Mississippi, Missouri, Montana, North Carolina, North Dakota, Pennsylvania, Texas, West Virginia, and Wyoming, EPA said.

The Sierra Club environmental group reacted to the MATS order by Trump, saying: “By rolling back the most recent update to those protections, the administration is senselessly prioritizing outdated, polluting energy sources over the well-being of American communities—maybe your community. The exempted power plants and coal-burning units are in every region of the country—from Arizona to Pennsylvania, Wyoming to Alabama, from the Dakotas down to Texas, and in Illinois, Indiana, Missouri, and throughout the Midwest.”

Other actions under consideration by EPA include:

Reconsideration of the Biden-Harris Administration’s Clean Power 2.0 regulations for power plants, which were struck down by the Supreme Court in 2022.

Revising Biden’s PM2.5 National Ambient Air Quality Standards regarding particulate emissions, with EPA saying it is a major obstacle to permitting new energy projects.

Reconsidering implementation of the Clean Air Act’s Regional Haze Program, which EPA said “has imposed significant costs on power plants and other sectors, calling into question the supply of affordable energy for American families.”

Advancing cooperative federalism and encouraging states to pursue oversight and permitting of coal ash within their borders.

Reviewing whether to extend compliance deadlines for the Legacy-Coal Combustion Residuals Management Units rule.

Rescinding EPA’s Guidance on the Preparation of Clean Air Act Section 179B, Demonstrations for Nonattainment Areas Affected by International Transport of Emissions, which EPA said, “made it unnecessarily difficult for states to demonstrate that foreign air pollution is harming Americans within their borders.”

EPA granted the Salt River Project’s Coronado Generating Station’s application for an extension of the deadline to meet requirements under the Resource Conservation and Recovery Act regulations for the management of coal ash.

In response to Trump’s declaration of a “National Energy Emergency,” Interior Secretary Burgum implemented emergency permitting for a list of domestic energy resources, including coal. Other resources include crude oil, natural gas, lease condensates, natural gas liquids, refined petroleum products, uranium, biofuels, geothermal, kinetic hydropower, and critical minerals.

“These measures are designed to expedite the review and approval, if appropriate, of projects related to the identification, leasing, siting, production, transportation, refining, or generation of energy within the United States,” a release from the Department of the Interior said.

The effort will reduce permitting from a multi-year process to a maximum of 28 days, according to the White House. Current delays in approvals of energy projects pose risks to the nation’s economic stability, national security, and foreign policy interests, it said. The efficiencies will use existing regulations under the National Environmental Policy Act, Endangered Species Act, and the National Historic Preservation Act.

Under the National Environmental Policy Act, projects requiring an environmental assessment that normally take up to one year will be reviewed in about 14 days, according to the agency, while projects that require a full environmental impact statement will see timelines reduced from about two years to 28 days.

An expedited consultation process under Section 7 of the Endangered Species Act will allow the energy-related bureaus to notify the Fish and Wildlife Service that they are using emergency procedures, and the decision whether to proceed will be left with the bureaus. Bureaus will also follow alternative procedures under the National Historic Preservation Act.

Sources used in this article:

Reinvigorating America’s Beautiful Clean Coal Industry and Amending Executive Order 14241| The White House

Establishing the National Energy Dominance Council | The White House

Regulatory Relief for Certain Stationary Sources to Promote American Energy | The White House

Administrator Zeldin Releases Statement on POTUS’ New Energy-Related EO Signed Today | US EPA

Poisoning Our Future: The Trump Administration’s Dangerous Coal Exemptions | Sierra Club

Declaring a National Energy Emergency | The White House

Interior Implements Emergency Permitting Procedures to Strengthen Domestic Energy Supply | US Department of the Interior

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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. 

Published: April 25, 2025

By Concentric Staff Writer

Key takeaways:

The Western utility landscape is set for major changes with the formation of two competing day-ahead market proposals: the California Independent System Operator’s (CAISO) extended day-ahead market (EDAM) and the Southwest Power Pool’s (SPP) Markets+.
Markets+ recently received support from a decision by the Bonneville Power Administration to join that market, while CAISO’s EDAM moved forward with the introduction of new legislation in California to create a regional organization to manage it.
SPP is also moving forward with an expansion of its existing regional transmission organization (RTO) from the Eastern Interconnection into the Western Interconnection, receiving approval from the Federal Energy Regulatory Commission (FERC) for what is known as RTO West.

There are major movements happening in Western wholesale energy markets, with two major competing efforts to launch a day-ahead trading market and billions of dollars in future market transactions at stake.

Across the West, the development of new day-ahead markets and the an RTO are the key factors Western utilities are monitoring as they determine which choice in a market is the optimal one. The goals of these markets are maintaining grid reliability and controlling costs for energy consumers, more efficient dispatch of power plants, and in many areas, enabling a transition to cleaner energy resources.

A recent seismic shift in Western energy markets occurred when Bonneville Power Administration (BPA), which markets power from 31 federal hydropower dams in the Northwest and manages 15,000 miles of high-voltage transmission lines, chose a day-ahead market to join. Western market players for years had been wondering where the federally regulated entity would land, but BPA on March 5 announced a “policy direction” that it will select the SPP’s Markets+ day-ahead market over the CAISO’s EDAM.

Utilities across the West are looking for the best place to collaborate on resource trading, which becomes critical during times of grid stress. In the West, this grid stress mostly occurs in summer evenings, when air conditioning load decrease solar output leads to peak grid demand.

Currently, the only two major Western organized regional markets are the CAISO market and its Western Energy Imbalance Market (WEIM), a real-time trading market that has led to billions of dollars in benefits for market participants. But the real-time market lacks day-ahead scheduling of power, which provides better reliability and scheduling abilities.

SPP has its own version of a regional market similar to CAISO’s WEIM, which is known as the Western Energy Imbalance Service Market. Imbalance markets differ from day-ahead markets in that they are real-time grid balancing markets and do not include day-ahead energy trading, which improves reliability, economic efficiency, and transparency .

The difference between a full RTO and the current visions of Markets+ and EDAM is that in an RTO, utilities and other participating entities hand over full control of their transmission systems to the RTO, which manages the dispatch of power plants and the flow of power. This is the system that has long been in place in regional markets that have operated across the country, such as the PJM Interconnection in the Mid-Atlantic, the Midcontinent Independent System Operator, and ISO New England.

CAISO’s EDAM has been under development for years and the tariff for the day-ahead market gained approval from the Federal Energy Regulatory Commission in December 2023. Entities that have announced intentions to join EDAM include the Los Angeles Department of Water & Power (2027), the Balancing Authority of Northern California (2027), PacifiCorp (2026), and Portland General Electric (2026). According to the CAISO, entities that are “leaning towards EDAM” are Idaho Power, NV Energy, BHE Montana, and Public Service Company of New Mexico.

SPP’s Markets+ is due to begin operations in 2027. In addition to BPA, Salt River Project, Tacoma Power, Arizona Public Service, Tucson Electric Power, and UniSource Energy Services have signed on to participate in the market.

The main issue around the emerging Western markets, which would bring the West into a more advanced market design similar to other RTOs around the country, is how the market will be governed and who will oversee it. Western states and California alike want to ensure that they retain control over resource mix and other planning and environmental decisions if and when they join an organized market.

Likewise, environmental groups and trade unions in California have resisted expanding CAISO into a regional market. Unions, a powerful force in the Golden State, have also opposed the regionalization of CAISO over worries that jobs will be lost to other states. As a result, for years, legislative attempts to regionalize CAISO in the California State Legislature have failed.

The CAISO Board of Governors is appointed by the California governor. The Board of Governors oversees the CAISO wholesale market, while the WEIM is governed by the WEIM Governing Body, which has shared authority with the CAISO board on many market decisions but is nominated by a nominating committee rather than being appointed by the governor.

In an effort to absolve these concerns about governance in the EDAM, the West-Wide Governance Pathways Initiative (WWGPI) was created in October 2023. The initiative was meant to ease concerns about governance through the creation of a regional organization (not a full-blown RTO) to manage the EDAM that is governed by multiple states, not just California. WWGPI officials are hoping that the initiative will lead to a full Western RTO.

The WWGPI got a major boost in late February when legislation was introduced to move the initiative forward, Senate Bill 540. The bill would allow the WWGPI and its transmission owners to participate in energy markets governed by the regional organization created through the WWGPI process. It has gained support from electrical worker and labor unions that have traditionally opposed the expansion of CAISO.

In a press release announcing the introduction of SB 540, bill sponsor Senator Josh Becker (D-Menlo Park) said, “As we move toward achieving California’s 100% clean energy goals, we must look at all possible solutions to reduce costs, improve reliability, and cut emissions,” Becker continued, “Pathways strikes that balance by unlocking the benefits of a regional energy market while safeguarding California’s critical public policy priorities. It offers a win-win scenario for California—achieving cleaner energy, more reliable power, and real savings for ratepayers.”

Little Rock, Arkansas-based SPP, which has operated an RTO in the Eastern Interconnection, has an expansion project underway into the Western Interconnection, known as RTO West.

The Federal Energy Regulatory Commission (FERC) on March 20 approved SPP’s tariff revisions for RTO West. It is the first RTO to have a footprint in both the Western and Eastern Interconnections. The RTO expansion is part of SPP’s five-year plan to bring western entities into its markets, known as ASPIRE 2026.

“I am pleased to announce FERC’s approval of the amended RTO tariff,” SPP president and CEO Barbara Sugg said in a press release. “Expanding the RTO into the Western Interconnection is an exciting step in SPP’s growth, bringing value to new and existing members while enhancing reliability in both interconnections.”

Utilities and others that plan to participate in RTO West are Basin Electric Power Cooperative; Colorado Springs Utilities; Deseret Generation and Transmission Cooperative; Municipal Energy Agency of Nebraska; Platte River Power Authority; Tri-State Generation and Transmission Association; and three regions of the Western Area Power Administration: Colorado River Storage Project, Rocky Mountain Region, and Upper Great Plains-West.

“The Western expansion of the SPP RTO bolsters reliability and resiliency for our members as we grow and diversify our resource portfolio while reducing emissions,” Tri-State Generation and Transmission Association CEO Duane Highley said in the release. “We greatly value the full benefits of the SPP RTO, including day-ahead and ancillary services markets, efficient regional transmission planning, a common transmission tariff and participatory governance model that help us to further reduce costs for our members across the West. Prior to SPP RTO West entry, we will be making a filing with our state regulators highlighting these market benefits.”

Some Western market participants have pointed out that the creation of two large day-ahead markets—EDAM and Markets+—will create a large “seam” across the West between the two markets. Markets without seams are considered favorable because one large market allows more resource sharing and more efficient plant dispatch, which would deliver greater reliability, cost, and environmental benefits. But unless Markets+ and EDAM are merged, it appears that this seam will be taking shape in the future.

There are many moving parts in play in the two day-ahead market proposals and much work still to be done, but it is clear that major changes are in the works for Western energy markets.

Background Information:

This article drew upon reports from materials from CAISO, SPP, WWGPI, and California legislation.

Links to Cited Sources:

ISO New England website

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Published: April 18, 2025

By Danielle Powers and Lisa Quilici

Key Takeaways

Both Maryland and Ohio have recently advanced energy legislation aimed at regaining control of their energy resource mix, accelerating the development of new in-State generation, meeting the growing demand for electricity, and controlling rising rates. Maryland’s General Assembly passed a package of energy-related bills, with the cornerstone being the Next Generation Energy Act, HB 1035/SB 937, which is now with the Governor. In Ohio, both the House and Senate have passed bills (HB 15 and SB 2); a single bill must be agreed upon before it can be presented to the Governor.

The recent settlement agreement involving PJM, Talen Energy, the Maryland Public Service Commission, electric utilities, and others, which would keep certain coal-fired plants operating, provides a backdrop to these legislative initiatives. If FERC approves the settlement, Talen Energy will operate the Brandon Shores and H.A. Wagner coal plants until May 31, 2029, four years longer than their scheduled retirement dates, under reliability-must-run agreements to allow for necessary transmission upgrades for grid reliability to be put in service.

The laws proposed in Maryland and Ohio demonstrate a growing concern about the ability of existing competitive market structures to adapt to evolving reliability, demand, and affordability needs. Rising and volatile market prices, wholesale market design challenges, and projections of significant load growth have prompted both states to pursue additional tools to ensure long-term service adequacy while minimizing customer costs.

If enacted, the new laws in Maryland and Ohio would mark a shift away from reliance on competitive wholesale markets.

Maryland

The Next Generation Energy Act, HB1035/SB937, aims to encourage the development of new generation resources, modernize the state’s energy infrastructure, and control rising electric prices, among other objectives. Key provisions of the Next Generation Energy Act would:

Promote the deployment of dispatchable energy generation, which as defined, would primarily include new natural gas generation provided it can be converted to use only hydrogen or zero-emission biofuel when the Public Service Commission determines such a conversion is feasible.

Promote the deployment of new battery storage.

Encourage the development of new nuclear power and support the extension or renewal of the Calvert Cliffs Nuclear Plant’s license.

Eliminate subsidies for trash incineration, and the eligibility of waste-to-energy and refuse-derived fuel to satisfy the State Renewable Energy Portfolio Standard (RPS).

Make the process and requirements for approval of gas infrastructure replacement projects more rigorous, including requirements to demonstrate public benefits.

Establish a separate rate class for large load customers and make clear “that residential electric customers in the State should not bear the financial risks associated with large load customers”.

Introduce various rate-related provisions intended to increase oversight of utility spending, such as requiring investor-owned utilities to demonstrate the reasonableness of the use of internal labor as compared to contracted labor in rate cases, and eliminate the ability of utilities with multi-year rate plans filed after January 1, 2025 from filing for reconciliation of cost or revenue variances.

Provide refunds of approximately $80 per household funded by payments made by utilities in lieu of complying with the state’s RPS.

Other bills in the package are HB1036/SB931, which would create uniform standards for solar energy projects, and HB1037/SB909, which would establish a state office focused on energy planning. If signed by the Governor, the Next Generation Energy Act will take effect June 1, 2025.

Ohio

Ohio currently has two significant energy reform bills under consideration: SB2 and HB15. Both aim to modernize the state’s energy policies, enhance consumer protections, and encourage new energy generation to meet increasing demand. Key provisions of SB2 and HB15 would:

Eliminate Electric Security Plans (ESPs) and require utilities to file full rate cases by December 31, 2029, and at least every three years thereafter.

Introduce customer refunds if the Public Utilities Commission of Ohio or the Ohio Supreme Court determines that charges were unreasonable, unlawful, or imprudent.

Expand the definition of “self-generator” to include entities that own or host electric generation facilities on property they control, not just on their premises. It also introduces “mercantile self-power systems” that can serve one or more mercantile customers, provided they meet specific criteria.¹

Create Priority Investment Areas (PIAs), allowing local governments to petition for the designation of brownfields or former coal mine sites as PIAs. Projects in these areas benefit from a five-year exemption from tangible personal property tax and expedited review processes by the Ohio Power Siting Board.

Reform to tangible personal property tax rates to incentivize new energy investments. For example, new generation facilities placed into service after the bill’s effective date are subject to a reduced tax rate, encouraging modernization and development.

Streamline regulatory timelines for decisions on certificate applications and rate case applications.

Prohibit electric distribution utilities from owning generation facilities or participating in the wholesale market, and restrict utility ownership of behind-the-meter generation systems, with certain grandfathering provisions for existing projects.

SB2 has been referred to the House Energy Committee. Both the House and Senate are working towards reconciling differences between SB2 and House Bill15, with the goal of presenting a single energy reform package to the Governor.

Other States

Maryland and Ohio are not alone in their energy reform initiatives. In December 2024, the Governor of Pennsylvania filed a complaint against PJM’s capacity auction design and anticipated price increases with FERC. In January, this case settled with PJM agreeing to lower its auction price cap by 35%. In 2021, Illinois enacted the Climate and Equitable Jobs Act (CEJA), directing utilities to procure capacity outside of PJM’s capacity market to regain control over resource procurement to align with affordability and decarbonization goals. Other states have or are currently studying exiting competitive markets.

Collectively, these examples underscore the growing tension between competitive market structures and state priorities, signaling that more states may explore ways to assert greater control over their energy futures.

Concentric Energy Advisors helps utilities, independent power producers, and government entities in responding to changes in public policy, resource planning, and wholesale electric market design and operational issues. Contact Danielle Powers, Chief Executive Officer, 508.263.6219.

¹Under SB2, a mercantile self-power system is a generation or storage facility that provides electricity directly to one or more large commercial or industrial customers without using the utility’s distribution system. These systems must be located on property owned or controlled by the customer or system operator. SB2 exempts them from regulation as utilities, enabling large users to self-supply power more easily.

Links to cited sources:

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

Published: April 16, 2025

By Concentric Staff Writer

Key takeaways:

Rising electricity demand was the story nationally in 2024, rising by 2.8 percent, primarily in the California Independent System Operator (CAISO), Electric Reliability Council of Texas (ERCOT), and the Mid-Atlantic region.
Generation retirements, which are worrying federal energy regulators, were primarily coal-fired power plants, followed by natural gas-fired plants, with the bulk of them in the Midcontinent Independent System Operator (MISO).
Independent system operators (ISOs) and regional transmission organizations (RTOs) made progress on clogged interconnection queues, with the capacity of projects in queues dropping for the first time on an annual basis.
There were also declines in wholesale electricity and natural gas prices across all ISOs and RTOs.

Last year was a tale of rising national energy demand, extreme weather that affected the electric grid, increased renewables, and slight progress on clogged interconnection queues, according to a new report from federal energy regulators.

The State of the Markets Report for 2024, issued March 20 by the Federal Energy Regulatory Commission (FERC), notes that after flat load growth in recent years, electricity demand grew by 2.8 percent over the year nationally. The largest load growth in 2024 was in California, while the biggest decrease was in the New York ISO. Half of the RTOs and ISOs saw load growth in 2023-2024 while the other half saw decreases, the report says.

FERC Chairman Mark Christie, who has been vocal on the issues of preparing the grid for forecasted increased demand, expressed alarm over generation retirements and an influx of renewables that have lower dispatch potential compared to conventional resources.

“This report is consistent with reports we have been regularly receiving from NERC [North American Electric Reliability Corporation] as well as RTO sources, such as from PJM and MISO,” Christie said in a news release. “The combination of rapidly increasing electricity demand, driven by hyperscale customers such as data centers, paired with the alarming rate of base load generation retirements and lack of new dispatchable generation, is not sustainable and must be addressed.”

The resource type seeing the most retirements was coal-fired power plants, although there were substantial retirements of natural gas-fired plants. The majority of retirements were in MISO, which had 3.6 GW of retirements last year in its region.

The biggest increase in electric load was in Southwest Power Pool (SPP) over the four-year period ending in 2024 with 8.3 percent, while the New York ISO saw the largest decrease at 4 percent. The largest increase over the 2020–2024 period was also in SPP. There were also declines in natural gas prices and wholesale energy prices in all ISOs and RTOs, but no corresponding price drops for retail consumers.

Extreme weather in the CAISO, ERCOT, and the Mid-Atlantic drove most of the demand growth in 2024, according to the report by FERC staff. There were also power outages and the disruption of oil and gas production on the Atlantic coast.

NERC projects that the pace of growth in electricity load will accelerate, estimated to grow by 132 gigawatts by the summer of 2029 and by 149 GW by the winter of 2029. Although natural gas prices spiked in January 2024 on cold weather, nationwide natural gas prices fell year over year and remained below the five-year average. One exception was in the Northeast, where natural gas prices rose slightly over 2023.

Natural gas prices, which drive wholesale electricity prices in many areas, dropped at major hubs outside the Northeast, such as the benchmark Henry Hub in Louisiana, which fell by 11 percent to $2.25 per million British thermal units (MMBtu), averaged over the year. The lower prices were mainly a result of higher-than-average storage levels, bolstered by little change in natural gas production and demand.

Natural gas demand reached an all-time high in 2024, according to the report, averaging 102.8 billion cubic feet per day (Bcfd) in the year, including net exports, while domestic consumption averaged 90.2 Bcfd. While growth in demand slowed over the year—at .5 percent compared to the five-year average of 3.1 percent growth in 2019–2023—the average of 36.9 Bcfd natural gas burn was a historical high. This was 4.2 percent growth year over year, with natural gas burned for electricity being the largest component of demand.

“Power burn exceeded the prior year’s level and the five-year average in nearly every month of 2024 in response to lower natural gas prices, coal power plant retirements, and natural gas-fired generation additions,” the report says.

U.S. dry natural gas production decreased slightly, by .3 Bcfd, ending at an average of 103.2 Bcfd. The most production came from the Permian Basin, followed by West Texas and Louisiana. Natural gas production in the Permian Basin increased 2.1 Bcfd or 13 percent over the year. The Waha Hub in West Texas had the lowest average spot natural gas price over the year, at $.05 per MMBtu, compared to $1.52 in 2023.

“Prices at the Waha Hub are typically lower than those at most natural gas trading hubs in the country due to a combination of limited natural gas pipeline takeaway capacity and growing gas production associated with oil-focused drilling,” the report says. “Waha spot natural gas prices were negative for 158 days, or 43 percent of the year, in 2024 as the region faced pipeline outages and takeaway capacity constraints.”

The biggest average price drops over the year were at SoCal Gas Citygate and PG&E Citygate in California, which saw a 62-percent drop to $4.12 per MMBtu at SoCal Gas Citygate and $3 per MMBtu at PG&E Citygate. There were also smaller natural gas price decreases—about 10 percent—at the Midcontinent hubs of Chicago Citygates in the Chicago area and NGPL-Midcon, which serves parts of Kansas, Oklahoma, and the Texas Panhandle.

Natural gas production averaged 103.2 Bcfd in 2024, a drop of .3 percent compared to the previous year, while natural gas demand grew by .5 percent to an average of 102.8 Bcfd. Prices outside the Northeast fell year over year by between $.18/MMBtu and $4.12/MMBtu across the major hubs.

However, prices at Northeast hubs rose, including 14 percent at Transco Zone 6 N.Y. serving New York City, 3 percent at Algonquin Citygates in the Boston area, and 2 percent at Eastern Gas South in Appalachia. This was due to cold weather, including a cold snap in mid-January that pushed up demand and prices.

As far as power generation, while most new capacity additions came from solar, natural gas, battery storage, and wind resources, natural gas retained a large share of the resource mix at about 42.4 percent nationally. Coal generation dropped by 3.3 percent; utility-scale solar grew by 32 percent; and wind rose by 7.7 percent in the lower 48 states. Net generation also rose in 2024 from the previous year, hitting 4,151 terawatt-hours (TWh).

Capacity prices in organized markets with capacity markets—PJM Interconnection, MISO, and ISO New England—also rose due to “electricity market dynamics,” according to FERC.

RTOs and ISOs adjusted their resource adequacy requirements, such as in SPP, which introduced new seasonal resource adequacy requirements, and in MISO, which set higher planning reserve margins for load-responsible entities. Challenges facing resource adequacy included the changing resource mix, extreme weather, and shifts in load profiles.

FERC in November 2024 approved SPP’s proposed tariff revisions to add a winter season resource adequacy requirement for load-responsible entities that took effect Jan. 1, 2025. The revisions required that these entities comply with winter resource-adequacy requirements or pay a deficiency payment.

Last year also marked the first time that the total capacity of new generation projects in interconnection queues dropped on an annual basis. Total capacity in queues around the country totaled 2,289 GW at the end of the year, the vast majority being solar, energy storage, and hybrid storage projects. These resource types represented 81 percent of the capacity in interconnection queues. Despite this, the resource types that made up most of the capacity entering queues in 2024 were natural gas generation and storage.

Efforts to clear out clogged interconnection queues continue, bolstered by FERC’s issuance in July 2023 of its Order No. 2023 that included many new processes for ISOs and RTOs to clear out queues. Individual RTOs and ISOs also enacted their own queue reform initiatives.

The largest amount of active interconnection queue capacity was in the Western region, with 590 GW, followed by MISO with 439 GW, and ERCOT with 351 GW. In MISO, the largest resource type sitting in interconnection queues was solar (241 GW), “which was the largest amount of active capacity in interconnection queues for all fuel types in all regions,” the report says.

More than 5,000 circuit miles of transmission projects entered service in 2024 nationally, mostly to address reliability needs. The most miles were built in CAISO, which had 2,000 miles of reliability projects built (as opposed to policy-driven projects), followed by ERCOT, MISO, and PJM, which had about 200 miles of new reliability-driven transmission added.

Across all the RTOs and ISOs, transmission projects driven by load growth included about 900 circuit miles—the second-largest category of new transmission. The smallest category of new transmission were policy-driven projects, with four such projects entering service in the year—two in CAISO and one in PJM and MISO, respectively. There was only one economic-driven project completed in the year.

The majority of projects were at the 138-kilovolt level, with this type making up 170 projects and almost 1,100 circuit miles, the report says. The majority of these were in ERCOT and PJM.

Sources used in this article:

FERC State of the Markets Report for 2024

FERC Order No. 2023

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Published: March 24, 2025

By Danielle Powers and Mark Karl

Key Takeaways:

While capacity markets have historically played an important role in supporting grid reliability, their foundational design no longer reflects the realities of today’s power grid. These markets were built around a generation fleet dominated by dispatchable resources, yet the current mix increasingly includes intermittent renewables and resources shaped by policy objectives.
Some of the core assumptions embedded in capacity market structures, such as the idea that all capacity resources contribute equally to reliability or that investment will consistently respond to price signals, have been called into question. Recent experiences with price volatility, shifting accreditation standards, and out-of-market interventions have raised concerns about whether these markets are sending the right signals to support long-term investment in reliability.
These challenges have prompted a broader conversation about whether the existing capacity market framework is sufficient on its own, or whether alternative models should be considered. Options such as bilateral contracting, centralized procurement, or new reliability products that reflect the specific attributes needed to operate the grid may offer more tailored solutions for today’s changing landscape.

For decades, capacity markets have played a central role in the design of wholesale power markets in the United States, particularly in regions such as PJM, ISO-New England, and NYISO. These markets were originally established to help ensure grid reliability by securing adequate generation to meet peak demand. However, as resource portfolios evolve, renewable energy grows in prominence, and policy priorities shift, questions have emerged about whether existing capacity market structures remain well-suited to today’s energy landscape. These developments have prompted discussion around whether incremental adjustments are sufficient, or if more substantial reforms may be necessary.

The Origins and Evolution of Capacity Markets

Capacity markets were introduced in the late 1990s and early 2000s as part of deregulation efforts in the energy sector. Their purpose was to address the missing money problem, which is the gap between the revenue that generating resources need to cover their fixed costs and the revenue they actually earn in the energy and reserves markets. Capacity markets were introduced as a solution to this problem, providing an additional stream of revenue to ensure sufficient investment in generation capacity and long-term grid reliability.

The fundamental assumption was that all power plants contributed equally to system reliability, that all megawatts were created equal, and that a simple auction-based market could incentivize investment in new resources as older ones retired. However, this model was built around a system dominated by traditional, dispatchable power plants—coal, natural gas, and nuclear generators—which provided energy and essential grid services such as voltage control, frequency stability, and inertia. These plants could be counted on to supply power and gird services whenever demand required it.

Another foundational element of capacity market design was that new generation entry would come as a result of a market signal for the needed capacity. The rapid expansion of renewable resources, along with the policies designed to incent and, in some cases, subsidize these resources, has upended these foundational assumptions. In addition, the price volatility and rule instability that result from constant “tweaking” of the design in an attempt to address shortcomings as they arise makes it difficult to support substantial investment.

Why Capacity Markets No Longer Work

Why are capacity markets increasingly seen as unsustainable in their current form? The reasons are simple: the foundational assumptions on which capacity markets were created no longer hold true.

Mismatch Between Capacity Markets and Modern Energy Resources
The original design of capacity markets assumed that all qualified capacity megawatts were functionally equivalent. This is no longer the case. The modern energy mix includes a growing share of intermittent renewables like wind and solar, which do not always generate electricity when needed. Capacity markets have attempted to adapt through mechanisms like the Effective Load Carrying Capability (ELCC) rating process, performance incentives, and fuel supply requirements, but these changes are incremental fixes that fail to address the full reliability need and fail to address the larger issue: capacity markets are designed for a power grid and a supply resource mix that no longer exists.
Distortion from Public Policy Interventions
The rise of state-level clean energy mandates and direct subsidies for renewables has further complicated capacity markets. Many new renewable projects are entering the market not because of price signals, but because they receive out-of-market financial support to achieve specific policy goals. All else being equal, this artificially suppresses capacity prices, making it even harder for traditional generators to remain viable. As a result, necessary resources are being pushed toward retirement, even when they are still essential for reliability. Capacity markets were never designed to accommodate these policy-driven shifts, and they have proven ineffective at integrating them into the broader reliability framework.
Failure to Account for Essential Grid Services
Traditional power plants provided a “bundle” of reliability attributes beyond just megawatts of capacity. They offered fuel security, , frequency regulation, and fast-ramping capabilities. Although different resource technologies provided different quantities of these attributes, for the most part, they provided the full “bundle.” New capacity resources, particularly renewables, do not inherently provide all these same services, yet capacity markets still treat them as interchangeable with traditional generators. This has led to reliability gaps, forcing grid operators like PJM to intervene with out-of-market payments to keep critical plants from shutting down. If grid operators must frequently override market outcomes to ensure reliability, it is a clear indication that the market is failing.
Increasing Market Volatility and Inefficiencies
Capacity market prices have become increasingly unstable, fluctuating from near-zero levels in oversupplied years to dramatic spikes when retirements accelerate. The most recent PJM Base Residual Auction saw prices jump nearly tenfold, largely due to resource retirements and new constraints placed on capacity accreditation. Such volatility discourages long-term investment in new generation, as developers cannot count on stable revenue streams. This instability undermines the very purpose of capacity markets, which is to provide financial certainty for generators and ensure long-term resource adequacy.
Inability to Adapt to Rapid Changes in Demand
Since capacity markets were first introduced, electricity demand in the U.S. has grown modestly overall. From the early 2000s to the mid-2010s, total electricity consumption remained relatively flat, influenced by improvements in energy efficiency, a shift toward a more service-based economy, and the decline of energy-intensive manufacturing. As a result, capacity markets provided sufficient incentive for the construction of new generation resources. However, the demand for electricity from data centers is expected to grow significantly in the coming years due to the rapid expansion of cloud computing, artificial intelligence (AI), cryptocurrency mining, and the electrification of the economy. According to the NERC 2024 Long-Term Reliability Assessment, summer peak demand for the U.S. is expected to grow by 132 GW over the next 10 years, significantly greater than the 80 GW projected in the 2023 assessment. Given the substantial challenges faced in recent years in meeting even modest load growth, it is extremely unlikely the current capacity construct and markets will be capable of delivering the resources needed in time to meet the projected increase.

What Comes Next? Alternatives to Capacity Markets

To borrow a phrase from FERC Chair Mark Christie, “we have a rendezvous with reality”. It is time to move beyond incremental adjustments to capacity markets and begin exploring alternative approaches to ensuring grid reliability. We can’t afford to continue to put reliability at risk when “baseload” retirements are happening faster than dispatchable generation can be added. As Chair Christie recently stated in comments made at CERAWeek when stressing the need for dispatchable resources to maintain grid reliability, “we’re simply not ready to run a grid where we don’t have dispatchable resources”. How can the current capacity market design incent dispatchable gas-fired resources critical to ensuring reliability when these resources might operate for a handful of peak hours during the year?

There are market designs, such as those used in MISO and ERCOT, that provide useful models. MISO relies on load-serving entities (LSEs) to demonstrate sufficient resource adequacy through bilateral contracts and self-supply options. ERCOT operates an “energy-only” market, where real-time prices reflect scarcity conditions and encourage investment in new capacity when needed.

Another viable approach is the creation of a centralized procurement agency—such as a state or regional power authority—that would oversee long-term reliability contracts. It is important to recognize that the creation of such an agency need not represent the abandonment of wholesale electricity markets. Certainly, the energy and reserves markets need not change, and can continue to provide the same efficiency benefits they do today.

The power authority need not own or operate supply resources either. Such an entity could competitively procure the right mix of resources on a contract basis from independent owners and operators to balance dispatchability, fuel security, reliability, affordability, and policy goals, rather than relying on an outdated market mechanism that no longer serves its intended purpose. The procurement process could also allow for self-supply by load serving entities, utilities, or municipal systems and would provide a more stable revenue stream to facilitate lower cost financing.

Conclusion

The electricity system is undergoing a fundamental transformation, and capacity markets are failing to keep pace. Designed for a different era, they no longer align with the realities of modern energy markets, technological advancements, and policy objectives. Instead of continuing to modify an outdated system, policymakers and grid operators should move toward market structures that better reflect today’s energy needs. Whether through direct procurement, LSE-led resource planning, or new reliability products that disaggregate the attributes currently assumed in the current capacity product, the time has come to move beyond capacity markets and embrace a model that ensures a reliable, cost-effective, and sustainable energy future.

Links to Cited Sources:

2024 Long-Term Reliability Assessment. North American Electric Reliability Corporation

“US Grid Must Embrace Natural Gas in ‘Rendezvous with Reality’: FERC Chair.” Upstreamonline.com

Published: March 7, 2025

By Concentric Staff Writer

Key takeaways

Historic amounts of energy storage, primarily lithium-ion battery systems, are being added to the U.S. grid, driven by a need to balance renewable generation and to meet load growth, including from data centers.
A series of fires at lithium-ion facilities, particularly in California and New York, have led to more scrutiny and resistance from the public to new facilities.
Issues with lithium-ion safety and sourcing are leading to more research into other types of energy storage, based on a variety of technologies.

Battery energy storage systems (BESS) are growing rapidly on the U.S. grid, but the technology has faced some headwinds. The primary technology being installed, lithium-ion storage facilities, have experienced fires that have some localities beginning to question the safety of living nearby.

BESS soared on the grid over the past few years, although the election of President Donald Trump could affect that total as he froze Inflation Reduction Act (IRA) funding that was driving new resource additions. The IRA included a 30 percent investment tax credit for standalone energy systems and solar/storage projects, if construction began in 2024.

The U.S. added 5 GW of new BESS in the first seven months of 2024, according to the U.S. Energy Information Administration (EIA). This compares to just 4 MW that was added back in 2010.

“Battery energy storage systems provide electricity to the power grid and offer a range of services to support electric power grids,” EIA said. “Among these services are balancing supply and demand, moving electricity from periods of low prices to periods of high prices (a strategy known as arbitrage), and allowing electricity from renewable sources, such as wind and solar, to be stored until needed instead of curtailing those sources at times when they produce more electricity than is consumed.”

At the beginning of 2024, EIA estimated battery storage would make up 23 percent of new resource additions over the year (14.3 GW) nation-wide, second only to solar additions which were projected to be 58 percent of new resources (36.4 GW). This compares with just 4 percent for natural gas (2.5 GW) and 13 percent for wind (8.2 GW).

EIA estimated battery energy storage to about double in 2024, with developers reporting plans to develop 14.3 GW storage to the existing 15.5 GW. In 2023, battery storage rose by 70 percent, with 6.4 GW of new additions, EIA said.

About 82 percent of new storage in 2024 was expected in Texas (6.4 GW) and California (5.2 GW).

Texas set a new record for solar/BESS additions in 2024, helping to manage the critical evening peak, according to research from the Federal Reserve Bank of Texas. But researchers noted cold winter conditions can hamper the availability of solar/BESS as peak demand in Texas shifts to morning hours, creating a “growing risk that the solar-battery pairing may be inadequate to meet demand, particularly if thermal (natural gas and coal) power plant outages exceed estimates.”

In the evening hours from 6 p.m.–9 p.m., discharge from BESS averaged 714 MW in 2024 in Texas. But batteries were important on certain days such as August 20, 2024, when a new peak demand record was set and BESS set its own record of 3,927 MW of output at 7:35 p.m.

Wholesale prices can also affect the growth of BESS, as real-time wholesale prices in the Electric Reliability Council of Texas averaged $28 in 2024, compared with $97 the year before. In the 6 p.m.–9 p.m. slot, wholesale prices averaged $80 in 2024 compared with $332 in 2023.

“While these prices are unquestionably better for consumers, this development has potentially negative implications for continued growth of battery storage and other forms of dispatchable generation,” the Federal Reserve said.

New York Governor Kathy Hochul in June announced plans for 6 gigawatts of energy storage in the state by 2030, part of the state’s roadmap of having 70 percent of the state’s electricity provided by renewables by 2030 and 100 percent zero-emission electricity by 2040. The plan implements the Climate Leadership and Community Protection Act, clean-energy legislation passed in 2019.

However, the projects are already receiving public resistance. On Staten Island, local residents created a petition against NineDot Energy’s 5 MW/20 MWh battery storage project, which is already under construction. Residents say they were taken by surprise by the new facility.

“This petition is personal to all of us who call this community our home because we understand the potential dangers associated with such a facility located so close to our residences. The community was not made aware of this site being built until last minute and we do not approve,” the petition says.

In Duanesberg, New York, town officials in January 2025 passed a resolution banning the construction of new energy storage facilities in the town.

In the Golden State, the California Public Utilities Commission (CPUC) on Jan. 27 proposed new standards for BESS. The proposed rules, due for implementation in March, adopt General Order 167-C (GO 167-C) “Enforcement of Maintenance and Operation Standards for Electric Generating Facilities and Energy Storage Systems.”

The proposed rules implement Senate Bill 1383 by Ben Hueso (D-San Diego County), then a state senator, which mandated standards for the maintenance and operation of energy storage systems and applies emergency response and action plan requirements to BESS facilities.

GO 167-C also would require BESS facility owners to coordinate with local authorities in developing their emergency plans and established “logbook standards,” to ensure consistency and auditing of safety protocols for energy storage and renewable energy facilities. It also adds provisions to increase safety for storage and generating assets and updates to certain procedures, references, and definitions.

The original GO 167 was originally adopted more than 20 years ago in 2004 to establish standards for power generation facilities. The order flowed from Senate Bill X2-39, which had been drafted in reaction to the California energy crisis of 2000-2001. As new renewable mandates took effect in California due to legislation like Senate Bill 100, there has been a large increase in renewable generation.

“California Air Resources Board (CARB) recognizes that energy storage systems play a key role in meeting SB 100 goals by balancing intermittent renewable energy and managing grid reliability and stability via ancillary services and capacity,” the CPUC said in the proposed order.

Along with the growth in renewable energy, energy storage has surged in the state from 500 MW in 2019 to 13,300 MW in 2024. About 11,600 MW of this is utility-scale storage capacity, representing a level equal to 22 percent of the state’s peak electric demand. The need for energy storage in California is estimated at 52,000 MW by 2045, the CPUC said. As defined in state standards, an energy storage facility is any technology capable of absorbing energy and storing it over time for later dispatch.

However, since the original GO 167 was written before the widespread adoption of renewable generation and BESS, a comprehensive view of the rule is needed for operation, maintenance and safety oversight of non-thermal generation technology, the state agency said.

There have been 10 safety incidents at BESS facilities in California since 2021 according to CPUC records.

But there are currently no provisions in GO 167 requiring BESS owners to report safety incidents such as injuries, fatalities, thermal runaways, fires, or other system failures. This has created a need for increased regulatory oversight of the technology, the CPUC said.

The CPUC held three workshops with industry stakeholders in 2024, where staff suggested changes to GO 167 and took comment, which was received from 12 organizations such as Calpine Corporation, California Energy Storage Alliance, and utilities and companies that operate BESS facilities.

Four days before Trump took office, DOE on January 16, 2025 announced $23 billion in loans for eight projects, including energy storage, transmission, clean generation, grid modernization, and natural gas pipeline investments. The loans allow lower-cost debt and financing costs compared to traditional financial markets, according to the federal agency. Among the projects was $3 billion to Alliant Energy subsidiaries for 2,000 MW of clean energy and storage in Iowa and Wisconsin, to be developed over the next years.

In San Luis Obispo County, Caballero CA Storage, LLC’s project is receiving some pushback from the local community, which has appeared at the county’s board of supervisors meetings to express concerns. The 100 MW/400 MWh facility in Nipomo was acquired by Alpha Omega Power in December 2024. The stored energy would be sold in the California Independent System Operator market.

Given some of the issues surrounding lithium-ion, it is likely that research in other types of energy storage batteries will increase, hopefully proving fewer challenges for developers and less concern to communities that sit near BESS facilities.

Background information and cited sources

U.S. EIA Today in Energy report

Federal Reserve Bank of Texas

New York Gov. Kathy Hochul news release

New York Climate Leadership and Community Protection Act

Change.org petition against new BESS project

Ninedotenergy news release

CPUC General Order 167-C

U.S. DOE news release

U.S. DOE Loan Programs Office news release

Businesswire news release

— 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.

Published: February 28, 2025

On January 31, 2025, Evergy utility subsidiaries filed a Motion to File Legal Analysis Regarding Standards for Determining Capital Structure with the Kansas Corporation Commission. This Motion was filed concurrently with an application for a general rate case.¹

Like many jurisdictions, capital structure has been a contested issue in Kansas. Due to the prevalence of black box settlements, the issue is not always fully litigated. In anticipation of heavy opposition to its proposal to use the actual standalone capital structure of its Kansas utilities in calculating revenue requirements, Evergy took the unusual step of proactively filing this Motion to provide the Commission with a legal foundation at the outset of the proceeding rather than during post-hearing legal briefing.

In summary, the Motion addresses:

The Commission’s policy to “use a capital structure that will result in the lowest overall cost of capital that is representative of utility operations”
The Standalone Approach
Consolidate Capital Structure and FERC’s three-part test
Hypothetical Capital Structures
Capital Structure and a Fair Rate of Return
Capital Structure and Corporate Veil-Piercing Principles
And concludes the Standalone Approach should be the presumptive standard and to overcome that presumption a party must present substantial competent evidence demonstrating the actual capital structure is imprudent or inconsistent with industry norms, or there has been intentional manipulation of corporate capitalization

Concentric Energy Advisors’ Cost of Capital practice helps North American utilities to understand the impact of regulatory activity such as the Evergy filing on their own businesses and regulatory strategies.

For more than twenty years, Concentric Energy Advisors has supported clients with a sophisticated and industry-based perspective on capital structure and return on equity. We have provided expert testimony and support to clients the United States and Canadian provinces. For more information, please contact info@ceadvisors.com

¹Before the State Corporation Commission of the State of Kansas, In the Matter of the Application of Evergy Kansas Central, Inc. and Evergy Kansas South, Inc. for Approval to Make Certain Changes in their Charges for Electric Service. Docket No. 25-EKCE-294-RTS

On February 20, 2025, the Federal Energy Regulatory Commission (“FERC”) issued a highly anticipated order under Section 206 of the Federal Power Act addressing concerns related to large loads co-located at generating facilities within the PJM Interconnection. The growing interest in co-location arrangements, particularly involving data centers and industrial facilities, has raised questions about how interconnected generators should serve these co-located loads when they are physically connected to an existing or planned generator on the generator side of the point of interconnection. These arrangements have introduced issues around potential cross-subsidization, cost shifting, grid reliability, resource adequacy, and jurisdictional boundaries.

In this show-cause order (“Order”), FERC found PJM’s Tariff to be potentially unjust, unreasonable, unduly discriminatory, or preferential for lacking explicit provisions on co-location arrangements. The Order highlighted several key issues:

1. Jurisdictional Debate:

Co-located arrangements introduce jurisdictional questions. Some stakeholders have argued that FERC’s jurisdiction should be limited to interstate wholesale transactions and that states should retain control over retail sales and behind-the-meter arrangements. Others argue that load served directly by a generator is analogous to behind-the-meter generation and is exempt from FERC oversight. PJM and others maintain that co-located loads still benefit from grid services and should thus fall under FERC’s oversight when those services affect wholesale rates and grid reliability.

2. Cost Allocation and Grid Services:

A significant concern is whether co-located loads can fully isolate from the electric grid and avoid paying their share of costs for transmission services and for ancillary services from PJM. PJM and its market monitor have argued that co-located loads should be treated like other grid-connected loads and should pay for network services, ancillary services, and capacity. Other stakeholders have countered that since co-located loads can fully isolate and not draw power from the grid, they should not incur transmission service charges.

3. Reliability and Resource Adequacy:

Several parties have highlighted potential risks that co-located loads might impose on grid stability, particularly when large loads bypass the traditional planning process. For example, sudden shifts in demand or the loss of a co-located generator could compromise grid stability. PJM emphasized that the rapid growth of such loads could strain existing capacity reserves and suggested that planning frameworks need adjustments to incorporate these arrangements effectively. However, proponents of co-located load arrangements have argued that such configurations can offer benefits like reducing grid congestion, easing interconnection backlogs, and energizing data centers more quickly.

In the Order, FERC directed PJM and the Transmission Owners to provide justifications for the current tariff or suggest changes within 30 days. These justifications must address concerns related to jurisdiction, cost allocation, reliability, and potential discriminatory practices. FERC requested answers to approximately 40 questions related to jurisdictional principles, the type of transmission service used under various configurations, cost allocation, and the impacts on the wholesale market and ancillary services.

Concentric Energy Advisors’ Wholesale Energy Markets practice helps utilities, independent power producers, and government entities shape and understand wholesale electric market design and operational issues. Contact Danielle Powers, Chief Executive Officer, at dpowers@ceadvisors.com or 508.263.6219 to learn more about our services.

Published: February 14, 2025

How can utilities ensure that the collection of depreciation expense remains accurate without the expense and rigor of a complete depreciation study?

Depreciation guidelines recommend conducting depreciation studies periodically to confirm that the depreciation rates in use remain appropriate, and to recognize the inherent variability in depreciable service lives and net salvage estimates. For these reasons, Concentric recommends that most utilities complete a full depreciation study every three to five years.

Usually, depreciation studies are performed as part of a utility’s rate case. However, there are instances when general rate applications may occur outside the three-to-five-year cycle of depreciation studies. This can create unique challenges in instances where, for example, a significant technological change requires the retirement of the majority of assets in an account or an account has been fully depreciated. The key question then becomes: How can utilities ensure that the collection of depreciation expense remains accurate without undertaking a full depreciation study?

A beneficial alternative for utilities to explore is a technical update or depreciation review. This option allows for the recalculation of depreciation expense based on the assets in service at the time of the update, without re-evaluating the underlying depreciation parameters. In practice, this means that the estimates of average service life and net salvage parameters remain unchanged, while the total depreciation expense is updated to ensure accuracy.

Since technical updates do not require a re-examination of depreciation parameters, they can be completed relatively swiftly and cost-effectively, requiring less labor from the utility. Many utilities choose to perform these updates annually to ensure that the book depreciation reserve aligns with expectations. This proactive approach empowers utilities to quickly identify any emerging issues and resolve questions about the underlying data without the pressure of an impending rate case.

With the significantly lower costs for technical updates, and the subsequent savings that are often realized in full depreciation studies, annual technical updates are highly recommended for many utilities. This strategy is particularly applicable for utilities using the Equal Life Group procedure; however, even those using the Average Life Group procedure typically benefit from annual technical updates.

Why Choose Concentric for your Depreciation Technical Update?

Our depreciation practice has nearly a century of combined technical experience.
Our lead team members are Certified Depreciation Professionals by the Society of Depreciation Professionals.
Concentric staff have successfully completed dozens of technical updates and more than 125 depreciation studies for clients across North America.

To learn more about Concentric’s proactive approach to a Depreciation Technical Update, please contact Amanda Nori.

Published: February 13, 2025

Concentric Energy Advisors and Concentric Advisors ULC are pleased to announce multiple promotions within our team.

We are proud to recognize our colleagues for their commitment to Concentric’s principles and clients as we continue to provide innovative solutions that power an evolving industry.

Mark Cattrell was promoted to Vice President

William (Bill) Davis was promoted to Vice President

Jennifer Nelson was promoted to Vice President

Bickey Rimal was promoted to Vice President

Joseph Weiss was promoted to Vice President

Alexander Cochis was promoted to Assistant Vice President

Marisa Ihara was promoted to Assistant Vice President

Amanda Nori was promoted to Assistant Vice President

Meredith Stone was promoted to Assistant Vice President

Jack Gross was promoted to Senior Consultant

Clara-Ann Joyce was promoted to Senior Consultant

Ryan Kennedy was promoted to Senior Consultant

Riley Burns was promoted to Consultant

Marcus Kim was promoted to Consultant

Sarah Quinn was promoted to Consultant

Jake Levingston was promoted to Senior Analyst

Katherine Judd was promoted to Senior Business Development and Marketing Analyst

Shaizee Vang was promoted to Staff Accountant

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